Exploration and Production
Cherokee Basin Operations
We have of over 3,000 gross and net wells capable of production, in the 15-county region in southeastern Kansas and northeastern Oklahoma known as the Cherokee Basin. 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 342,449 net acres of leasehold classified as developed. In addition, we have approximately 72,121 net acres classified as undeveloped in the Cherokee Basin. During 2012, net production from our Cherokee Basin wells was an average of 43.6 MMcfe/d. At year end, our reservoir engineers attributed 69.1 Bcfe of estimated net proved reserves 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.
Other Areas of Operation
We have of over 400 gross and net wells capable of production in the Appalachian Basin. These wells are on approximately 8,851 net acres of leasehold classified as developed. In addition, we have approximately 24,045 net acres classified as undeveloped in the Appalachian Basin. During 2012, net production from our Appalachian Basin wells was an average of 1.8 MMcfe/d. At year end, our reservoir engineers attributed 8.2 Bcfe of estimated net proved reserves to these properties.
We also have approximately 28 gross and 20 net wells capable of production in central Oklahoma. These wells are on approximately 1,315 net acres of leasehold classified as developed. In addition, we have approximately 120 net acres classified as undeveloped in central Oklahoma. During 2012, net production from these wells averaged 155 Bbls/d. At year end, our reservoir engineers attributed 1.41 MMbbl of crude oil and 14.91 MMcf of natural gas, or a total of 8.53 Bcfe, of estimated net proved reserves to these properties.