Lonestar Resources

Headquartered in Fort Worth, Texas, Lonestars focus is on the volatile crude oil window of the Eagle Ford Shale, where we anticipate spending almost all of our capital for the next several years. We “went public” through our merger with Amadeus Energy, Ltd. on January 2, 2013 to better position the Company to pursue its core strategy of growing its leasehold position (currently in excess of 60,000 net acres), production, cash flow and reserve base in one of the most active onshore basins in the U.S.

SEASONED GROUP OF OIL AND GAS PROFESSIONALS

Lonestar is managed from the Companys headquarters in Fort Worth, Texas by a seasoned group of oil and gas professionals with extensive experience, much of which has been at prominent, successful public companies in the U.S.

Focused on Eagle Ford Crude Oil Window

Our operational focus is on our Eagle Ford position located in eleven Texas counties, which are divided into three distinct regions: Western Eagle Ford (Dimmit, La Salle and Frio Counties), Central Eagle Ford (Gonzales, Karnes, Fayette, Wilson, DeWitt and Lavaca Counties) and Eastern Eagle Ford (Brazos and Robertson Counties). As of December 31, 2017, we operated 81% of our Eagle Ford position and approximately 89% of our acreage was held by production (HBP).

As of December 31, 2017, our Eagle Ford properties had proved reserves of 73.6 MMBoe, of which 84% was crude oil and NGLs and 25% was proved developed producing (PDP). The PV-10 of our Eagle Ford proved reserves as of December 31, 2017 was $538.3 million using SEC pricing, (44% PDP), and $647.6 million using NYMEX strip pricing (42% PDP).   Third-party engineers have identified more than 250 gross horizontal drilling locations on our Eagle Ford acreage, of which 61% are expected to be drilled using lateral lengths of, or greater than, 7,000 feet and 95% are expected to be drilled using lateral lengths of, or greater than, 5,000 feet.

In the Eagle Ford, we are focused on geo-engineered completions where an integrated approach to drilling, completion, stimulation, and production of laterals is driving ongoing improvement in well results. We use vertical pilot logs to select geo-targets to optimize both reservoir and mechanical properties. We also apply an azimuthal gamma ray logging while drilling (LWD) tool to assist in geosteering, while multi-planar gamma ray data determines dip angle and direction in real time.

We run lateral thru-bit logs to total depth (TD) for detailed rock properties analysis, and mangrove stimulation design, which utilizes thru-bit log data for reservoir characterization and models key mechanical properties to optimize stimulation. We have also been increasingly using diverters, where an engineered fibrous pill is designed to create near-wellbore isolation that augments frac efficacy across all perforations, maximizing wellbore coverage. In addition, we have increasingly applied controlled flowbacks, where solids and fluids analysis are implemented to avoid negative impact of hydraulic fractures and assess success of completion strategies.

Finally, we are focused on longer is better. While the incremental cost of going from a 5,000 ft. lateral to 10,000 ft. is approximately 50%, the increase in net reserves, PV-10, and IRR is greater than 100%. Our inventory of more than 250 gross engineered locations have an average lateral length of approximately 8,000 ft. and climbing, with the first wells in 2018 ranging from 10,400 ft. at Hawkeye to 12,350 ft. at Horned Frog.