The Appalachian Basin is one of the country\'s oldest natural gas producing regions characterized by long-lived reserves and predictable decline rates. During the first several years of production, Appalachian Basin wells generally experience higher initial production rates and decline rates which are followed by an extended period of significantly lower production rates and decline rates. The average well production in the Appalachian Basin is 10 Mcf per day or less and decline rates typically range from 2% to 6% per year.

The Appalachian Basin spans more than seven states in the largest natural gas consuming region of the United States. The close proximity to major natural gas consuming markets in the northeastern United States results in lower transportation costs to these markets relative to natural gas produced in other regions, contributing to the premium pricing for Appalachian production relative to NYMEX. Further, supply of natural gas from the Midwest, Rockies and Canadian regions may face transportation and storage capacity constraints during peak winter season.

Reserves in the Appalachian Basin typically have a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

Most of the Company’s wells are relatively shallow, ranging from 2,500 to 5,500 feet, and drill through as many as ten potential pay zones. In general, the Company’s producing wells have stable production profiles and long-lived production, often with total projected economic lives in excess of 50 years. Once drilled and completed, operating and maintenance requirements for producing wells in the Appalachian Basin are generally low and only minimal, if any, capital expenditures are required. Appalachian wells typically are drilled on relatively close spacing of between 20 to 40 acres per well due to the low permeability of the producing formations. Generally, the distance between wells is less than 1,500 feet and wells are located within 1,000 feet from the closest pipeline. As a result, most of the Company’s wells are producing and connected to a pipeline within 60 days (some as quickly as 11 days) after drilling has commenced.

The Company owns and operates an extensive network of natural gas gathering systems comprised of 350 miles of pipeline and associated compression and metering facilities which connect to numerous sales outlets on eight interstate and eight intrastate pipelines.

The Company performs limited natural gas gathering activities through its subsidiary on non-jurisdictional gathering systems. The Company gathers for others primarily in Westmoreland and Indiana Counties, Pennsylvania. The fee charged to third party producers is set by contract and ranges from $0.10 to $0.25 per Mcf plus line loss and any compressor fuel.

The Company seeks to be the operator of wells in which it has an interest. As operator, the Company designs and manages the development of a well and supervise operation and maintenance activities on a day-to-day basis. The Company does not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties it operates. Independent contractors engaged by the Company provides all the equipment and personnel associated with these activities. The Company employs drilling, production, and reservoir engineers, geologists and other specialists who work to improve production rates, increase reserves, and lower the cost of operating its natural gas properties.

Operating expenses increased $689.0 thousand, or 60%, to $1.8 million for the quarter ended March 31, 2005 from $1.1 million during the quarter ended March 31, 2004.

Depreciation, depletion and amortization increased to $1.0 million for the quarter ended March 31, 2005 from $0.6 million during the quarter ended March 31, 2004.

Interest and financing expenses were ($19.6 million) for the quarter ended March 31, 2005 compared to $0.8 million for the quarter ended March 31, 2004.