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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2016

(a) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

Accounts Receivable

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of June 30, 2016 or December 31, 2015.

The Company accrues revenue due to timing differences between the delivery of natural gas, natural gas liquids (NGLs), and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees. The Company had $21.6 million and $19.9 million of accrued revenues, net of certain expenses at June 30, 2016 and December 31, 2015, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets.

Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “Depreciation, Depletion and Amortization” below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s condensed consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s condensed consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s condensed consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

	June 30, 2016			December 31, 2015
Oil and natural gas properties:
Unproved	$	684,383		$	720,159
Proved		1,338,546			1,288,609
Gross oil and natural gas properties		2,022,929			2,008,768
Less accumulated depreciation depletion and amortization		(1,075,477	)		(1,022,771	)
Oil and natural gas properties, net		947,452			985,997
Other property and equipment		11,169			10,753
Less accumulated depreciation		(3,746	)		(2,782	)
Other property and equipment, net		7,423			7,971
Property and equipment, net	$	954,875		$	993,968

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

The Company capitalized interest expense totaling $0.3 million and $1.1 million for the three months ended June 30, 2016 and 2015, respectively. The Company capitalized interest expense totaling $0.5 million and $2.6 million for the six months ended June 30, 2016 and 2015, respectively.

Other Property and Equipment

Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.

Revenue Recognition

(d) Revenue Recognition

Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil and NGLs in which the Company has an interest with other producers are recognized using the sales method on the basis of the Company’s net revenue interest. The Company did not have any material imbalances as of June 30, 2016 or December 31, 2015.

In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense.

Brokered natural gas and marketing revenues include revenues from brokered gas or revenue the Company receives as a result of selling and buying natural gas that is not related to its production and revenue from the release of transportation capacity. The Company realizes brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenue and expense in accordance with U.S. GAAP. The Company considers these activities as ancillary to its natural gas sales and thus, reports them within one operating segment.

Concentration of Credit Risk

(e) Concentration of Credit Risk

The Company’s principal exposures to credit risk are through the sale of its oil and natural gas production and related products and services, joint interest owner receivables and receivables resulting from commodity derivative contracts. The inability or failure of the Company’s significant customers or counterparties to meet their obligations or their insolvency or liquidation may adversely affect the Company’s financial results. The following table summarizes the Company’s concentration of receivables, net of allowances, by product or service as of June 30, 2016 and December 31, 2015 (in thousands):

	June 30, 2016		December 31, 2015
Receivables by product or service:
Sale of oil and natural gas and related products and services	$	21,625	$	19,858
Joint interest owners		2,493		3,095
Derivatives		1,294		4,523
Miscellaneous other		73		—
Total	$	25,485	$	27,476

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s unsettled commodity derivative contracts was a net liability position of ($12.6) million and a net asset position of $34.4 million at June 30, 2016 and December 31, 2015, respectively. Other than as provided by the its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are such counterparties required to provide credit support to the Company. As of June 30, 2016 and December 31, 2015, the Company did not have past-due receivables from or payables to any of such counterparties.

Accumulated Other Comprehensive Income (Loss)

(f) Accumulated Other Comprehensive Income (Loss)

Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Company they include a pension benefit plan that requires the Company to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its consolidated balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was terminated in October 2015 and lump sum payments were made in final settlement to all remaining participants.

Depreciation, Depletion and Amortization

(g) Depreciation, Depletion and Amortization

Oil and Natural Gas Properties

Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties totaled approximately $20.4 million and $60.1 million for the three months ended June 30, 2016 and 2015, respectively, and $35.0 million and $102.2 million for the six months ended June 30, 2016 and 2015, respectively.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation totaled approximately $0.5 million and $0.5 million for the three months ended June 30, 2016 and 2015, respectively, and $1.0 million and $0.8 million for the six months ended June 30, 2016 and 2015, respectively. This amount is included in DD&A expense in the condensed consolidated statements of operations.

Impairment of Long-Lived Assets

(h) Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review for impairment of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. As a result of the decline in commodity prices, the Company recognized impairment expenses of approximately $17.7 million for the six months ended June 30, 2016 relating to proved properties in the Marcellus Shale. There were no impairments of proved properties for the three or six months ended June 30, 2015 or the three months ended June 30, 2016.

The aforementioned impairment charge represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $9.4 million and $4.4 million for the three months ended June 30, 2016 and 2015, respectively, and approximately $18.7 million and $6.0 million for the six months ended June 30, 2016 and 2015, respectively. The increase in impairment charges during the three and six months ended June 30, 2016 is the result of an increase in expected lease expirations due to the reduction in the Company’s planned future drilling activity due to the current commodity pricing environment. These costs are included in exploration expense in the condensed consolidated statements of operations.

Income Taxes

(i) Income Taxes

The Company accounts for income taxes, as required, under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.

Fair Value of Financial Instruments

(j) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market date for substantially the entire contractual term of the asset or liability.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Derivative Financial Instruments

(k) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.

Derivatives are recorded at fair value and are included on the condensed consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.

The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.

Asset Retirement Obligation

(l) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate, which was 10.33% and 10.45% for the six months ended June 30, 2016 and 2015, respectively.

Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration, inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table sets forth the changes in the Company’s ARO liability for the six months ended June 30, 2016 (in thousands):

	Six Months Ended
	June 30, 2016
Asset retirement obligations, beginning of period	$	3,401
Additional liabilities incurred		63
Accretion		175
Asset retirement obligations, end of period	$	3,639

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

Lease Obligations

(m) Lease Obligations

The Company leases office space under operating leases that expire between the years 2016 to 2025. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease terms unless the renewals are deemed to be reasonably assured at lease inception.

Off-Balance Sheet Arrangements

(n) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

Segment Reporting

(o) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

Debt Issuance Costs

(p) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

Recent Accounting Pronouncements

(q) Recent Accounting Pronouncements

The FASB issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”)”, which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

In August 2014, the FASB issued ASU 2014-15, “Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” The new standard provides guidance on determining when and how to disclose going concern uncertainties in the financial statements. Management will be required to perform interim and annual assessments of the Company’s ability to continue as a going concern within one year of the date and financial statements are issued. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods within those years, with early adoption permitted. The adoption of this standard is not expected to have a significant impact on the Company’s financial statement disclosures.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity will be required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. The Company is evaluating the impact of the adoption of ASU 2016-02 on its financial position, results of operations and related disclosures.

In March 2016, the FASB issued ASU 2016-09, “Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” The new standard provides guidance involving several aspects of the accounting for share-based payments transactions, including income tax consequences, award classification as liabilities or equity, and cash flow statements classifications. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is evaluating the impact of the adoption of ASU 2016-09 on its financial position, results of operations and related disclosures.

Change In Estimates

(r) Change in estimates

During the three months ended June 30, 2016, the Company reduced its estimate of amounts due from a non-operated partner related to the sale of natural gas and NGLs, net of associated costs, based on revised information received from the non-operated partner during the period. As a result, the Company decreased accounts receivable by approximately $4 million, increased revenue from oil and natural gas sales by approximately $1.5 million, and increased transportation, gathering and compression expense by approximately $5.8 million, which increased the net loss for the three and six months ended June 30, 2016 by approximately $4 million, or $0.02 per common share.

During the six months ended June 30, 2016, the Company reduced its estimate for production and ad valorem tax expense based on recent historical experience and additional information received during the period. As a result, the Company decreased the accrual for production and ad valorem taxes to be paid by approximately $4 million, which decreased the net loss for the six months ended June 30, 2016 by a corresponding amount, or $0.02 per common share.