ECR Eclipse Resources Corp.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Organization and Nature of Operations

Eclipse Resources Corporation (the “Company”) is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale and Marcellus Shale prospective areas.

Note 2—Basis of Presentation

The accompanying condensed consolidated financial statements are unaudited except the condensed consolidated balance sheet at December 31, 2017, which is derived from the Company’s audited financial statements, and are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. All such adjustments are of a normal recurring nature.  These interim condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements, and the notes to those statements, which are included in the Company’s Annual Report on Form 10-K filed with the SEC on March 2, 2018.

Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2018 or any other future periods.

Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3— Summary of Significant Accounting Policies describes our significant accounting policies. The Company’s management believes the major estimates and assumptions impacting the condensed consolidated financial statements are the following:

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.

Note 3—Summary of Significant Accounting Policies

(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.

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(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 March 31, 2018 or December 31, 2017.

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 $51.3 million and $52.9 million of accrued revenues, net of certain expenses, at March 31, 2018 and December 31, 2017, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets.

(c) 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 the 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. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s consolidated statements of operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. 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):

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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 $0.5 million and $0.4 million for the three months ended March 31, 2018 and 2017, 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.

(d) Revenue Recognition

Product Revenue

The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received one month after the sale has occurred.

Natural Gas

Under the Company’s natural gas sales contracts, the Company delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellhead to delivery points specified under sales contracts. To deliver natural gas to these points, the Company uses third parties to gather, compress, process and transport the natural gas.  The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense.

NGLs

The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company delivers the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials.  The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs to further process and transport NGLs are recorded as transportation, gathering and compression expense.

Oil

Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks near central stabilization facilities and collect a contractually agreed upon index price, net of pricing differentials. The Company transfers control of the product from the central stabilization facilities to the purchaser and recognizes revenue based on the contract price.

Marketing Revenue

Brokered natural gas and marketing revenues are derived from activities to purchase and sell third-party natural gas and to market excess firm transportation capacity to third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore the Company recognizes revenue on a gross basis, with costs to purchase and transport natural gas presented as brokered natural gas and marketing expense. Contracts to sell third party natural gas are generally subject to similar terms as contracts to sell the Company’s produced natural gas and NGLs.  The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the price received from the purchaser.

Disaggregation of Revenue

  The following table illustrates the revenue disaggregated by type for the three months ended March 31, 2018 and 2017:

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Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less.  For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations is part of a contract that has an original expected duration of one year or less.

For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.  Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.  Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.

Contract Balances

Under the Company’s sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional.  Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.  Accounts receivable attributable to the Company’s revenue contracts with customers was $51.3 million and $52.9 million at March 31, 2018 and December 31, 2017, respectively.

(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 March 31, 2018 and December 31, 2017 (in thousands):

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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 conditi on 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 pote ntial 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 de rivative 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 ne tting 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 ($8.9) million a nd ($5.1) million at March 31, 2018 and December 31, 2017, respectively. Other than, as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contract s, nor are such counterparties required to provide credit support to the Company. As of March 31, 2018 and December 31, 2017, the Company did not have past-due receivables from or payables to any of such counterparties.

(f) 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 $30.7 million and $25.7 million for the three months ended March 31, 2018 and 2017, 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 for each of the three months ended March 31, 2018 and 2017. This amount is included in DD&A expense in the condensed consolidated statements of operations.

(g) 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.  There were no impairments of proved properties for the three months ended March 31, 2018 or the three months ended March 31, 2017.

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the Company’s forecasted discount net cash flows.

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The determination of oil and natural gas reserve estimates is a subjective process, and the a ccuracy 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 oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. 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 $6.7 million and $4.1 million for the three months ended March 31, 2018 and 2017, respectively. The increase in impairment charges during the three months ended March 31, 2018 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 price environment. These costs are included in exploration expense in the condensed consolidated statements of operations.

(h) 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.

(i) 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 data for substantially the entire contractual term of the asset or liability.  The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

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.

(j) Derivative Financial Instruments

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

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Derivatives are recorded at fair value and are included on the condensed c onsolidated 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 an y 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.

(k) 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% for each of the three months ended March 31, 2018 and 2017.

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 three months ended March 31, 2018 (in thousands):

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.

(l) Lease Obligations

The Company leases office space under an operating lease that expires in 2024. The lease term begins 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 term unless the renewals are deemed to be reasonably assured at lease inception.

(m) Off-Balance Sheet Arrangements

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

(n) 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.

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(o) 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.

(p) Recent Accounting Pronouncements

The FASB issued ASU 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.  The Company adopted this standard effective January 1, 2018 using the modified retrospective method.  The Company did not recognize a significant impact on its financial position or results of operations.  Upon adoption of this new standard, the Company did not record a cumulative effect adjustment nor did the Company alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify the impact of future revenue contracts entered into by the Company.  Additional disclosures have been included to provide further detail regarding the Company’s revenue recognition policies.  

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 with early adoption permitted. The Company plans to adopt this standard effective January 1, 2019 using the modified retrospective transition method and is evaluating the standard’s applicability to its various contractual arrangements.  Although the Company believes that the adoption of the standard will result in increases to its assets and liabilities on its consolidated balance sheet as well as changes to the presentation of certain operating expenses on its consolidated statement of operations, the Company has not yet determined the extent of the adjustments that will be required upon implementation of the standard.  The Company continues to monitor relevant industry guidance regarding the implementation of the standard.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.”  The new standard provides guidance on how certain cash receipts and cash payments are presented and classified on the statement of cash flows.  These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company adopted this standard effective January 1, 2018 and did not recognize a significant impact on its financial position, results of operations, or statement of cash flows.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.”  Currently under the standard, there are three elements of a business: inputs, processes and outputs.  The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets.  If that screen is met, the set of assets is not a business.  The new framework also specifies the minimum required inputs and processes necessary to be a business.  This amendment is effective for periods after December 15, 2017, with early adoption permitted.  The Company adopted this standard effective January 1, 2018 and considered the new guidance in its assessment of the accounting treatment for the Flat Castle Acquisition. (See Note 4— Acquisition ).

Note 4—Acquisition

On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, one producing well and other oil and gas rights and interests covering approximately 44,500 net acres located in Tioga and Potter Counties, Pennsylvania from Travis Peak Resources, LLC for an aggregate adjusted purchase price of $90 million, which was paid entirely with approximately 37.8 million shares of the Company’s common stock (the “Flat Castle Acquisition”).  The transaction was accounted for as an asset acquisition.  Approximately $86 million of the purchase price was allocated to unproved oil and natural gas properties and approximately $4 million was allocated to proved oil and gas properties associated with the producing well acquired.  In addition, the Company capitalized approximately $1 million of transaction costs related to the acquisition.  

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Note 5—Sale of Oil and Natural Gas Property Interests

During the three months ended March 31, 2018, the Company received approximately $3.8 million from a completed asset sale to a third party totaling approximately 400 acres.  No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the three months ended March 31, 2018, the Company received approximately $0.3 million from an additional completed asset sale to a third party totaling approximately 50 acres.  As a result of this sale, the Company recognized a gain of approximately $0.3 million.

Note 6—Derivative Instruments

Commodity Derivatives

The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.

The Company is exposed to credit risk in the event of non-performance by counterparties. To mitigate this risk, the Company enters into derivative contracts only with counterparties that are rated “A” or higher by S&P or Moody’s. The creditworthiness of counterparties is subject to periodic review. As of March 31, 2018, the Company’s derivative instruments were with Bank of Montreal, Citibank, Goldman Sachs, Morgan Stanley, Capital One N.A., BP Energy Company and KeyBank N.A. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of March 31, 2018, for future production periods:

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The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the condensed consolidated statements of operations for the periods presented (in thousands):

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Note 7—Fair Value Measurements

Fair Value Measurement on a Recurring Basis

The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the condensed consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. The fair value of the Company’s derivatives is based on third-party pricing models, which utilize inputs that are readily available in the public market, such as natural gas and crude oil forward curves. These values are compared to the values given by counterparties for reasonableness. Since the Company’s derivative instruments do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. 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 the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 3— Summary of Significant Accounting Policies ).

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 3— Summary of Significant Accounting Policies ).

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 8— Debt ).

Note 8—Debt

8.875% Senior Unsecured Notes Due 2023

On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% senior unsecured notes due 2023 at an issue price of 97.903% of the principal amount of the notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the senior unsecured notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside the United States in compliance with Regulation S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers’ discounts and estimated offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding Senior PIK Notes. The Company used the remaining net proceeds to fund its capital expenditure plan and for general corporate purposes.

During the three months ended March 31, 2018 and 2017, the Company amortized $0.9 million and $0.8 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.

The indenture governing the senior unsecured notes contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain

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liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company a nd its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the indenture. In ad dition, if the senior unsecured notes achieve an investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the indenture has then occurred and is continuing, many of such covenants will be suspended. The indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the inde nture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. T he Company was in compliance with all applicable covenants in the indenture at March 31, 2018.

Based on Level 2 market data inputs, the fair value of the senior unsecured notes at March 31, 2018 was $482.0 million.

Revolving Credit Facility

During the first quarter of 2014, Eclipse Resources I, LP, a wholly owned subsidiary of the Company (“Eclipse I”), entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that was scheduled to mature in 2018. Borrowings under the revolving credit facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October).

In January 2015, the credit agreement governing the revolving credit facility was amended and restated (as amended and restated, the “Credit Agreement”), primarily to add Eclipse Resources Corporation as a party thereto and thereby subject the Company to the representations, warranties, covenants and events of default provisions therein.  Relative to Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, Eclipse Resources Corporation rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I.  Other terms of the Credit Agreement remained generally consistent with Eclipse I’s previous credit agreement.

On February 24, 2016, the Company amended the Credit Amendment to, among other things, adjust the quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense, and to permit the sale of certain conventional properties. The amendment to the Credit Agreement also increased the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5% and required the Company to, within 60 days of the effectiveness of such amendment, execute and deliver additional mortgages on the Company’s oil and gas properties that include at least 90% of its proved reserves.

On February 24, 2017, the Company entered into an additional amendment to the Credit Agreement that increased the borrowing base from $125 million to $175 million, while extending the maturity of the revolving credit facility to February 2020.  In addition, this amendment modified the minimum interest coverage ratio covenant to a net leverage covenant of Net Debt to EBITDAX.  On August 1, 2017, the Company entered into an additional amendment to the Credit Agreement that increased the borrowing base from $175 million to $225 million.  

At March 31, 2018, the borrowing base was $225 million and the Company had $65 million in outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $33.6 million and the outstanding borrowings of $65 million, the Company had available borrowing capacity under the revolving credit facility of $126.4 million at March 31, 2018.  Subsequent to March 31, 2018, the Company repaid $20 million on the revolving credit facility, which reduced the outstanding borrowings to $45 million and resulted in available borrowing capacity of $146.4 million.  In April 2018, the Company completed its most recent borrowing base redetermination, which resulted in no change to the borrowing base of $225 million.  The Company’s next scheduled borrowing base redetermination is expected to be completed by October 2018.

The revolving credit facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all applicable covenants under the revolving credit facility as of March 31, 2018. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.5% of the unused facility based on utilization.

Note 9—Benefit Plans

Defined Contribution Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation

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contributed to the plan. The Company recorded compensation expense related to matching contributions, classified under general and administrative, of $0.2 million and $0.2 million for the three months ended March 31, 2018 and 2017, respectively.

Note 10—Stock-Based Compensation

The Company is authorized to grant up to 25,000,000 shares of common stock under its Amended and Restated 2014 Long-Term Incentive Plan (as amended, the “Plan”). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, qualified performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 7,199,257 shares were available for future grants under the Plan as of March 31, 2018.

Our stock-based compensation expense was as follows for the three months ended March 31, 2018 and 2017 (in thousands):

Restricted Stock Units

Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock and restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of March 31, 2018, there was $7.0 million of total unrecognized compensation cost related to outstanding restricted stock units. The weighted average period for the shares to vest is approximately 1 year. A summary of restricted stock unit awards activity during the three months ended March 31, 2018 is as follows:

Performance Units

Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return, as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of March 31, 2018, there was $6.4 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the shares to vest is approximately 2 years. A summary of performance stock unit awards activity during the three months ended March 31, 2018 is as follows:

The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk free rate and a volatility estimate tied to the Company’s stock price.  Prior to 2018, the volatility estimate was tied to the Company’s public peer group.  The following table presents the

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assumptions used to determine the fair value for performance stock units granted during the three months ended March  31, 2018 and 2017:

Restricted Stock Issued to Directors

On May 18, 2016, the Company issued an aggregate of 149,448 restricted shares of common stock to its three non-employee  members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which became fully vested on May 18, 2017.  For the three months ended March 31, 2017, the Company recognized expense of approximately $0.1 million related to these awards.

On May 17, 2017, the Company issued an aggregate of 153,192 restricted shares of common stock to its three non-employee members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which are scheduled to fully vest on May 17, 2018.  For the three months ended March 31, 2018, the Company recognized expense of approximately $0.1 million related to these awards.  As of March 31, 2018, there was approximately less than $0.1 million of total unrecognized compensation cost related to outstanding restricted stock issued to the Company’s directors.

Note 11—Earnings (Loss) Per Share

Earnings (Loss) Per Share

Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. During periods in which the Company incurs a net loss, diluted weighted-average shares outstanding are equal to basic weighted-average shares outstanding because the effect of all equity awards is antidilutive.  The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the three months ended March 31, 2018 and 2017, respectively:

Note 12—Related Party Transactions

During the three months ended March 31, 2018, the Company incurred approximately $0.2 million related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which are owned by the Company’s Chairman, President and Chief Executive Officer.  The Company incurred approximately $0.1 million related to such services during the three months ended March 31, 2017.  The fees are paid in accordance with a standard service contract that does not obligate the Company to any minimum terms.

Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap.  EnCap has representatives on the Board, and affiliates of EnCap collectively beneficially own a majority of the outstanding shares of our common stock. (See Note 4— Acquisition ).

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Note 13—Commitments and Contingencies

(a) Legal Matters

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

(b) Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

(c) Leases

The development of the Company’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent that the Company is not the operator of oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties.

The Company leases office space under an operating lease that expires in 2024. The Company recognized rent expense of $0.2 million and $0.2 million for the three months ended March 31, 2018 and 2017, respectively.

Note 14—Income Tax

For the year ending December 31, 2018, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items. The Company expects to incur both a book and tax loss in fiscal year 2018, and thus, no current federal income taxes are anticipated to be paid.  The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to the Company’s year-to-date loss.  On December 22, 2017, the Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, resulted in the reduction in the U.S. statutory rate from 35% to 21%.    For the three months ended March 31, 2018, the Company’s overall effective tax rate on operations was different than the federal statutory rate of 21% due primarily to valuation allowances and other permanent differences.

The Company’s interest expense deduction has the potential to be limited as a result of the enactment of the Tax Cuts and Jobs Act; however, the impact is anticipated to be minimal as a result of its full valuation allowance.  Future interpretations relating to the passage of the Tax Cuts and Jobs Act which vary from our current interpretation, and possible changes to state tax laws in response to the recently enacted federal legislation, may have a significant effect on our future taxable position.  The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.

In forecasting the 2018 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2018. Management reached this conclusion considering several factors such as: (i) the Company’s short tax history, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in the Company’s balance sheet. At this time, the estimated valuation allowance to be recorded in 2018 is $5.3 million.

Note 15—Subsidiary Guarantors

The Company’s wholly-owned subsidiaries each have fully and unconditionally, joint and severally, guaranteed the Company’s 8.875% senior unsecured notes. (See Note 8— Debt ). The Parent company has no independent assets or operations. The Company’s wholly owned subsidiaries are not restricted from transferring funds to the Parent or other wholly owned subsidiaries. The Company’s wholly owned subsidiaries do not have any restricted net assets.

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A subsidiary guarantor may be released from its obligations under the guarantee: