When we began the redesign of Carrizo following the last industry downcycle, our goal was to build core positions in high-quality, low-cost crude oil and condensate resource plays, as we believed these would provide better returns through our industry cycles than the natural gas plays that we were operating in at the time. We began by building acreage positions in the Eagle Ford Shale and Niobrara Formation during 2010, and have now grown these positions to approximately 84,000 and 33,600 net acres, respectively. During 2011, we began building a position in the Utica Shale, and have grown that to approximately 27,300 net acres. Most recently, we began to build a position in the Delaware Basin during 2014, which we have now grown to approximately 22,000 net acres.
Our acreage is concentrated in some of the most economical basins in North America.
These acreage positions give us access to some of the best rock in North America, and we currently have a drilling inventory of approximately 1,800 net locations across them, enough to grow our production for years to come. And the majority of our drilling inventory is at the low end of the North American cost curve, with nearly 55% of it economical below $40/Bbl WTI. The crown jewel of our acreage position is the Eagle Ford Shale, which we believe ranks as one of the top two or three plays in North America, with the Delaware Basin and Midland Basin being the others. In the Eagle Ford Shale alone, we have approximately 915 net undrilled locations in our inventory, with more than 80% of these being economical below $40/Bbl WTI.
While we do have a sizable drilling inventory, we are actively seeking to expand it, both through acquiring more acreage in our core plays as well as increasing the number of locations on our existing land positions. For example, in the Eagle Ford Shale, we are currently conducting multiple well density tests, such as infill drilling, Lower Eagle Ford stagger-stack tests, and Upper Eagle Ford tests, that have the potential to more than double our existing drilling inventory in the play.
During 2015, we ran two to four operated rigs and drilled 88 gross (76 net) operated wells; we also completed 82 gross (69 net) operated wells. Approximately 80% of the activity during the year was in the Eagle Ford Shale. This resulted in another year of strong growth in oil production, as we averaged approximately 23,100 Bbls/d during 2015, up from approximately 18,900 Bbls/d in the prior year.
Our 2016 plans call for a decreased level of activity given the current commodity price environment. We currently plan to run one to two operated rigs during the year, which should allow us to drill 49 gross (46 net) operated wells. Given the flexibility provided by our backlog of drilled-but-uncompleted wells, we plan to complete more wells this year than we drill. Current plans call for us to complete 67 gross (60 net) operated wells in 2016. The program remains focused on the Eagle Ford Shale, with more than 90% of the planned activity allocated to that play. This level of activity should result in us holding 2016 crude oil production roughly flat with the approximately 25,000 Bbls/d we produced in the fourth quarter of 2015. We should also end 2016 with an inventory of drilled-but-uncompleted wells that will provide continued flexibility in future years.
We take great pride in having the right team in place to meet the challenges of creating and delivering long-term value for our shareholders. Our lean operations have allowed us to remain a profitable company during various economic downturns during our 20+ year history. We employ over 200 professionals, with approximately 35% being technical employees such as geophysicists, geologists, and engineers working in integrated teams across our asset base. Our management team averages more than 30 years of experience while our technical and operational teams average approximately 20 years of experience working for companies such as Shell, Texaco, Unocal, Continental Resources, and Devon Energy. In addition to our core competency of horizontal drilling and hydraulic fracturing, our team also has significant experience in building large acreage positions and analyzing subsurface data such as 3-D seismic.
We are one of the most experienced resource play companies in the industry, having drilled over 800 horizontal wells.
Our team has delivered consistently strong results. This requires not only commitment, but respect, hard work, and a collaborative mindset. We have a decentralized organizational structure, which allows our asset teams to drive performance. This cross-functional team approach fosters constructive creativity and collaboration throughout the organization. Teams are able to transfer results from their tests and quickly pick up best practices from other regions.
We believe our extensive experience has led to a competitive advantage in identifying, planning, and executing resource play projects. As a company, we have drilled over 800 horizontal wells, covering more than 10 million feet of measured depth, and completed over 12,000 frac stages in various resource plays including the Eagle Ford, Niobrara, Utica, Marcellus, and previously, the Barnett. Our understanding of prospective shale trends has helped us identify new plays early and move in relatively quickly and inexpensively. It has also helped us exit non-productive trends before significant capital has been spent. As an example, we were one of the first public companies to enter the Barnett Shale back in 2003, and became one of the lowest-cost, fastest-growing operators in the play. We were then able to use this knowledge to be one of the first companies to acquire Eagle Ford Shale acreage in La Salle County, which is now part of the core volatile oil window of the play.
While our assets do tend to be located in advantageous parts of the plays in which we operate, our well results also consistently rank among the best in these areas. This can be attributed to the technical and operational expertise that our team brings to the assets, both from the drilling and completion side. On the drilling side, our team is experienced in identifying and landing lateral wellbores in the narrow section of rock that exhibits the best geologic traits, and which should have the best productivity. On the completion side, our team is generally at the forefront of techniques that eventually become best practices in the industry. For example, we were one of the early adopters of using multiple entry points with high proppant concentrations in well completions in order to more effectively stimulate the rock near the wellbore.
While our historical results have been strong, our team also regularly tests new technologies to see if they can deliver improved well results or operational efficiencies. This should allow us to remain one of the most capital efficient operators in our industry and maximize the value of our asset base for our shareholders.
While the oil and gas industry is often considered to be an “old economy” industry, nothing could be further from the truth. The energy industry was one of the early users of supercomputers back in the early 1960s, and these remain an integral component in the discovery and development of new hydrocarbon reserves. In fact, our industry currently ranks as the world leader in commercial supercomputing. And this is just one example of how technology is prevalent in the oil and gas industry. At Carrizo, we strive to be at the forefront of new technology and ideas, and seek to adapt these in order to enhance the returns we generate from our assets. Using new technologies, we constantly try to maximize the hydrocarbon recovery from our assets and minimize our costs. And during 2015, gains from implementing new technologies helped us do just that.
We explore and adapt new technology that can enhance our returns.
At the beginning of the second quarter of 2015, we picked up a pair of newly-built, custom-designed Generation 3 drilling rigs. With these rigs, we were able to match our downhole directional equipment with new drilling motors to fully utilize the rigs’ capabilities; an added benefit was being able to limit the well path corrections needed to stay in target. The results were dramatic, as we were able to significantly increase the rate of penetration while drilling the wells. This has allowed us to reduce the drilling time for long-lateral wells in the Eagle Ford Shale from 16 days in 2014 to an average of 9 days by year-end 2015; and we’ve recently drilled some long-lateral wells in as few as 6 days. These efficiency gains, coupled with service cost reductions, have helped us drive well costs in the Eagle Ford Shale down from $7.5 million in late 2014 to $4.6 million today. And while oilfield service costs may rise as commodity prices increase, we should keep the efficiency gains that we’ve achieved, thereby enhancing the economics of our future drilling program.
Leveraging new technologies has also allowed us to increase the productivity of our wells. In shale plays, hydrocarbons do not typically flow without assistance. The wells produce economic quantities of hydrocarbons only after permeability has been created through a dense network of tiny fractures along the wellbore. By determining how to more optimally stimulate the reservoir, we can increase recovery factors as well as drive higher returns.
In 2015, Carrizo worked closely with Halliburton to utilize new proppant diversion technologies in a large-scale field trial in hopes of increasing the amount of reservoir rock stimulated along the wellbore, thereby improving well performance. We tested the new stimulation technology on 19 wells across five multi-well pad locations. In order to obtain additional diagnostics and subsurface insight, we also installed fiber-optic cables along the lateral section of one wellbore and utilized advanced micro-seismic to monitor the well completion in real-time. The data we obtained showed that the wells utilizing this new stimulation technology consistently performed better than the control wells without it, which we expect will lead to higher reserves and increased profitability.
New technologies are constantly being introduced in our industry. By staying on top of them, we expect to remain one of the lowest-cost producers in North America.
While having high-quality assets and a strong team are requirements for the creation of long-term shareholder value, we view an appropriate financial strategy to be equally important. As we operate in a capital-intensive cyclical industry, we seek to strike a balance between minimizing our cost of capital while maintaining a conservative balance sheet that provides us with sufficient liquidity to maximize our long-term growth through the cycles.
In general, we prefer to maintain a simple capital structure, focusing on common equity, unsecured bonds, and our revolving credit facility. These currently make up the vast majority of our capital structure. In order to maximize our liquidity during downcycles, the majority of our debt funding typically comes from our bonds. This keeps the capacity on our revolving credit facility available for times when accessing the equity or debt markets may be prohibitively expensive. We seek to manage our bonds over time in order to minimize our interest expense, as well as to minimize the risk that sizable maturities will come due during industry downcycles. To this end, we replaced $600 million of 8.625% bonds with $650 million of 6.25% bonds in early 2015. While this reduced our annual interest expense by approximately $11 million per year, it also extended the maturity of the notes from 2018 to 2023. As a result, we have no near-term maturities for our debt.
We have ample liquidity to execute our capital plan in the current environment.
Given our focus on minimizing the cost of capital, we had historically been comfortable operating our business with a net-debt-to-adjusted-EBITDA ratio of around 4.0x. However, following the last industry downturn, we decided that the potential for increased commodity price volatility necessitated a more conservative balance sheet. We also felt this would have a positive effect on our long-term cost of capital by reducing our weighted-average cost of equity through the cycles. As a result, from 2011 through 2014, we materially strengthened our balance sheet through our oil-weighted production growth combined with proceeds from asset sales. This reduced our net-debt-to-adjusted-EBITDA ratio to approximately 2.0x before the current downcycle began in mid-2014.
We seek to provide additional stability and cash flow visibility by employing an active hedging strategy. We typically target hedging 50%-75% of our production on a rolling 12-month basis. This helps protect our capital program and allows us to invest through the cycles rather than simply react to them. For 2016, we currently have hedges on approximately 14,800 Bbls/d, or approximately 60% of our forecast oil production, at a weighted-average floor price of approximately $64/Bbl. We have also begun adding hedge protection in 2017, and currently have approximately 12,000 Bbls/d hedged for the first half of the year at approximately $51/Bbl.
We exited 2015 with a net-debt-to-adjusted-EBITDA ratio of 2.7x, an undrawn $685 million revolver, and cash on the balance sheet. Combined with our strong hedge book, we believe that we have ample liquidity to execute our 2016 capital plan, which is designed to hold our crude oil production relatively flat while many of our competitors are experiencing declines. This should put us in a strong position to generate top-tier production growth once we get an appropriate commodity price signal.