Item 2. Properties

Principal facilities are owned or, in the case of certain office locations, warehouse buildings and equipment, leased, by the Company and its subsidiaries. The majority of the Company’s properties are located on or under (i) private properties owned in fee, held by lease or occupied under perpetual easements or other rights acquired for the most part without warranty of underlying land titles or (ii) public highways under franchises or permits from various governmental authorities. The Company’s facilities are generally well maintained and, where appropriate, are replaced or expanded to meet operating requirements.

The Company’s properties are located primarily in Pennsylvania, West Virginia and Ohio. The Company has approximately 1.4 million gross acres (approximately 74% of which are considered undeveloped), which encompass substantially all of the Company’s acreage of proved developed and undeveloped natural gas and oil producing properties. Of these gross acres, approximately 1.1 million are in the Marcellus play, much of which has associated deep Utica or Upper Devonian drilling rights, and approximately 0.1 million are in the Ohio Utica play. Although most of the Company's wells are drilled to relatively shallow depths (5,000 to 8,500 feet below the surface), the Company retains what are normally considered “deep rights” on the majority of its acreage. As of December 31, 2018, the Company estimated its total proved reserves to be 21.8 Tcfe, consisting of proved developed producing reserves of 11.3 Tcfe, proved developed non-producing reserves of 0.2 Tcfe and proved undeveloped reserves of 10.3 Tcfe. Substantially all of the Company’s reserves reside in continuous accumulations.

The Company’s estimate of proved natural gas, NGLs and oil reserves is prepared by Company engineers. The engineer primarily responsible for preparing the reserve report and the technical aspects of the reserves audit received a bachelor’s degree

in Chemical Engineering from the Pennsylvania State University and has 21 years of experience in the oil and gas industry. To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves. Additionally, division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems, and the reserve reconciliation between prior year reserves and current year reserves is reviewed by senior management.

The Company’s estimate of proved natural gas, NGLs and oil reserves is audited by the independent consulting firm of Ryder Scott Company, L.P. (Ryder Scott), which is hired by the Company’s management. Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. In the course of its audit, Ryder Scott reviewed 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company’s interests as of December 31, 2018. Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties. This audit covered 81% of the Company’s proved developed reserves. Ryder Scott’s audit of the remaining approximately 19% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 115 wells per case for non-operated wells. For undeveloped locations, the Company determined, and Ryder Scott reviewed and approved, the areas within the Company’s acreage considered to be proven. Reserves were assigned and projected by the Company’s reserves engineers for locations within these proven areas and approved by Ryder Scott based on analogous type curves and offset production information. Ryder Scott’s audit report has been filed herewith as Exhibit 99.

No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Company’s estimated total reserves. Additional information relating to the Company’s estimates of natural gas, NGLs and crude oil reserves and future net cash flows is provided in Note 18 (unaudited) to the Consolidated Financial Statements.

In 2018, the Company commenced drilling operations (spud or drilled) on 117 gross horizontal Marcellus wells, 5 gross horizontal Upper Devonian wells and 31 gross horizontal Ohio Utica wells. Sales volumes in 2018 from the Marcellus play, including the Upper Devonian play, was 1,230 Bcfe. Over the past five years, the Company has experienced a 97% developmental drilling success rate.

Natural gas, NGLs and crude oil pricing:

For additional information on pricing, see “Average Realized Price Reconciliation” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The Company’s average per unit production cost, excluding production taxes, of natural gas, NGLs and oil during 2018, 2017 and 2016 was $0.07 per Mcfe, $0.13 per Mcfe and $0.15 per Mcfe, respectively.

Summary of productive and in process natural gas and oil wells at December 31, 2018:

Summary of proved natural gas, oil and NGLs reserves as of December 31, 2018 based on average fiscal year prices:

As of December 31, 2018, the Company had no proved undeveloped reserves that had remained undeveloped for more than five years.

The Company has an active lease renewal program in areas targeted for development. In the event that production is not established or the Company takes no action to extend or renew the terms of its leases, the Company's net undeveloped acreage that will expire over the next three years as of December 31, 2018 is 90,543, 79,107 and 54,373 for the years ended December 31, 2019, 2020 and 2021, respectively.

Number of net productive and dry exploratory and development wells drilled:

The dry developmental wells in 2018 and 2017 are primarily related to non-core wells no longer planned to be drilled to depth or completed and acquired wells with mechanical integrity issues. The number of dry developmental wells drilled in 2016 were primarily related to vertical wells that are no longer planned to be drilled horizontally due to the uncertainty of identifying a near-term pipeline solution.

The table below provides select production, sales and acreage data by state (as of December 31, 2018 unless otherwise noted), which is substantially all from the Appalachian Basin. NGLs and oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods. Refer to the "Average Realized Price Reconciliation" table in Item 7 of this Annual Report on Form 10-K for sales volumes by final product.

(a) All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs.

(b) Other primarily includes Kentucky and Virginia. During 2018, as a result of the Huron Divestiture, the Company sold approximately 2.5 million non-core, net acres in the Huron play, however, the Company retained the deep drilling rights across the divested acreage in Kentucky and Virginia of 1.5 million and 0.2 million, respectively, which are excluded from the acreage totals above. Natural gas, oil and NGLs production and sales primarily represents activity prior to the completion of the 2018 Divestitures.

The Company sells natural gas and NGLs within the Appalachian Basin and in markets accessible through its transportation portfolio under a variety of contractual agreements, some of which specify the delivery of fixed and determinable quantities. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves. As of December 31, 2018, the Company’s delivery commitments for the next five years were as follows:

During the year ended December 31, 2018, the Company’s total proved developed reserves increased by 252 Bcfe. The increase in proved developed reserves was primarily due to the conversion of approximately 2,722 Bcfe of proved undeveloped reserves to proved developed reserves, an upward revision of 459 Bcfe from processing, ownership changes, and other revisions and the addition of 315 Bcfe due to extensions, discoveries, and other additions that were not previously recorded as proved reserves. These increases were partly offset by the sale of hydrocarbons in place of 1,749 Bcfe associated with the 2018 Divestitures as described in Note 8 and 2018 production of 1,495 Bcfe.

The Company’s 2018 extensions, discoveries and other additions totaled 4,739 Bcfe, which exceeded the 2018 production of 1,495 Bcfe. Of these, 315 Bcfe of proved developed reserves were extensions from reservoirs underlying acreage not previously booked as proved, 886 Bcfe of proved undeveloped reserves were extensions from acreage proved by drilling activity, and 3,538 Bcfe of other proved undeveloped additions are associated with acreage that was excluded from prior year proved reserves bookings, but subsequently became proved due to inclusion with the Company’s five year drilling plan.

The Company’s 2018 revisions totaled a downward adjustment of 1,125 Bcfe which was primarily due to the removal of certain proved undeveloped locations that are no longer expected to be developed within 5 years of initial booking as proved reserves, resulting from changes in Company’s future development plans to focus more heavily on developing the Company’s core Pennsylvania assets.

Wells located in Pennsylvania and West Virginia are primarily in Marcellus formations with depths ranging from 5,000 feet to 8,500 feet. Wells located in Ohio are primarily in Utica formations with depths ranging from 8,500 feet to 10,500 feet.

The Company’s corporate headquarters is located in leased office space in Pittsburgh, Pennsylvania. The Company also owns or leases office space in Pennsylvania, West Virginia and Ohio.

See “Capital Resources and Liquidity” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a discussion of capital expenditures.