Exploration and Production
Cherokee Basin Operations
We have over 2,700 gross and net wells capable of production in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma. The Cherokee Basin is a prolific producer of coal bed methane ("CBM") with an estimated 6 TCF of potential gas recovery according to the Kansas Geologic Survey.
Our Cherokee Basin wells are on approximately 324,500 net acres of leasehold classified as developed. In addition, we have approximately 38,500 net acres classified as undeveloped in the Cherokee Basin. During 2014, net production from our Cherokee Basin wells was an average of 34.6 Mmcf/d and 183 BOPD. At year end, our reservoir engineers attributed 106.9 Bcf and 0.9 MMBbl of estimated net proved natural gas and oil reserves, respectively, to these properties.
We are the largest producer of natural gas in the Cherokee Basin. Additionally, we own, operate and maintain our own fleet of equipment, including cementing, fracture treatment and well servicing rigs, to control capital and operating expenditures. We believe owning this equipment allows us to complete and operate our wells for a lower cost than our peers who rely upon third-party service providers. We also use state of the art SCADA systems to maximize field reliability and we have developed an artificial lift technology specifically optimized for our Cherokee Basin wells, significantly improving our well productivity.
We operate approximately 99% of our existing Cherokee Basin wells and have an average net revenue interest of approximately 82% in those wells. A typical Cherokee Basin CBM well has a predictable production profile and a standard economic life of approximately 15-20 years. We develop our CBM reserves on both 160-acre and 80-acre spacing.
Cherokee Basin Geology
The Cherokee Basin is part of the Western Interior Coal Region of the central United States. The coal seams we target for development are found at depths of 300 to 1,400 feet. The principal formations we target include the Mulky, Weir-Pittsburgh and the Riverton. These coal seams are blanket type deposits, which extend across large areas of the basin. Each of these seams generally range from two to five feet thick. Additional minor coal seams such as the Summit, Bevier, Fleming and Rowe are found at varying locations throughout the basin. These seams range in thickness from one to two feet.
The rock containing conventional gas, referred to as "source rock," is usually different from reservoir rock, which is the rock through which the conventional gas is produced, while in CBM, the coal seam serves as both the source rock and the reservoir rock. The storage mechanism is also different. Gas is stored in the pore or void space of the rock in conventional gas, but in CBM, most, and frequently all, of the gas is stored by adsorption. This adsorption allows large quantities of gas to be stored at relatively low pressures. A unique characteristic of CBM is the gas flow can be increased by reducing the reservoir pressure. Frequently, the coal bed pore space, which is in the form of cleats or fractures, is filled with water. The reservoir pressure is reduced by pumping out the water, releasing the methane from the molecular structure, which allows the methane to flow through the cleat structure to the well bore. Because of the necessity to remove water and reduce the pressure within the coal seam, CBM, unlike conventional hydrocarbons, often will not show immediately on initial production testing. Coal bed formations typically require extensive dewatering and depressurizing before desorption can occur and the methane begins to flow at commercial rates.
CBM and conventional gas both have methane as their major component. While conventional gas often has more complex hydrocarbon gases, CBM rarely has more than 2% of the more complex hydrocarbons. Once coal bed methane has been produced, it is gathered, transported, marketed and priced in the same manner as conventional gas. The CBM produced from our Cherokee Basin properties has an MMBtu content of approximately 970 MMBtu, compared to conventional natural gas hydrocarbon production which can typically vary from 1,050-1,300 MMBtus.
At December 31, 2014, our Central Oklahoma oil assets consisted of 72 gross and 57 net wells capable of production. These wells are on approximately 10,700 net acres of leasehold, classified as developed. In addition, we have approximately 23,000 net acres classified as undeveloped in the region. During 2014, net production from these wells increased 140% to a total of 196,287 barrels of oil, or an average of 538 Bbls/d. At year end, our estimated proved reserves attributable to these properties included 3.6 Bcf of natural gas and 3.0 MMBbl of oil or 21.6 Bcfe.
At December 31, 2014, we had 403 gross and 377 net wells capable of production in the Appalachian Basin. These wells are on approximately 8,800 net acres of leasehold classified as developed. In addition, we have approximately 4,600 net acres classified as undeveloped in the Appalachian Basin. During 2014, net production from our Appalachian Basin wells was an average of 1.3 MMcfe/d of natural gas and 32 Bbls/d of oil. At year end, our estimated proved reserves attributable to these properties included 8.7 Bcf of natural gas and 0.2 MMBbl of oil or 9.8 Bcfe.