Exhibit 99.5

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Managers and Members
Vantage Energy II, LLC:

We have audited the accompanying consolidated balance sheets of Vantage Energy II, LLC and subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations, changes in members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015.  These consolidated financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Vantage Energy II, LLC and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

Denver, Colorado
July 26, 2016

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VANTAGE ENERGY II, LLC

Consolidated Balance Sheets

December 31, 2015 and 2014

(In thousands)

See accompanying notes to consolidated financial statements.

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VANTAGE ENERGY II, LLC

Consolidated Statements of Operations

Years ended December 31, 2015, 2014, and 2013

(In thousands)

See accompanying notes to consolidated financial statements.

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VANTAGE ENERGY II, LLC

Consolidated Statements of Changes in Members’ Equity

Years ended December 31, 2015, 2014, and 2013

(In thousands)

See accompanying notes to consolidated financial statements.

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VANTAGE ENERGY II, LLC

Consolidated Statements of Cash Flows

Years ended December 31, 2015, 2014, and 2013

(In thousands)

See accompanying notes to consolidated financial statements.

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VANTAGE ENERGY II, LLC

Notes to Consolidated Financial Statements

December 31, 2015, 2014, and 2013

(1) Description of Business and Summary of Significant Accounting Policies

(a) Nature of Operations and Principles of Consolidation

Vantage Energy II, LLC (the Company) was organized as a limited liability company under the laws of the state of Delaware in 2012.  The consolidated financial statements include the accounts of Vantage Energy II, LLC and its two wholly owned subsidiaries.  All intercompany balances have been eliminated in consolidation.

The Company is engaged in the exploration and exploitation of petroleum and natural gas, as well as natural gas acquisition, development, and gathering, with a focus in unconventional resources in the Appalachian Basin of the United States.

(b) Use of Estimates

The preparation of these consolidated financial statements, in conformity with generally accepted accounting principles in the United States of America, requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes.  As a result, actual amounts could differ from estimated amounts.  By their nature, these estimates are subject to measurement uncertainty, and the effect on the consolidated financial statements of changes in such estimates in future periods could be significant.  Significant estimates with regard to the Company’s consolidated financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows, the recoverability of unproved oil and gas properties, the calculation of depletion of oil and gas reserves, the estimated cost and timing related to asset retirement obligations, and the estimated fair value of derivative assets and liabilities.

Reserve estimates are, by their nature, inherently imprecise.  The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data.  The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.  As a result, material revisions to existing reserve estimates may occur from time to time.  Although every reasonable effort is made to ensure that the reserve estimates represent the most accurate assessments possible, subjective decisions, and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures,

(c) Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.  The Company continually monitors its positions with, and the credit quality of, the financial institutions with which it invests.  As of the balance sheet date, and throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits.

(d) Oil and Gas Properties

The Company follows the full-cost method of accounting for natural gas and crude oil properties.  All costs associated with property acquisition, exploration, and development activities are capitalized.  Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves.  Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized.  For the years ended December 31, 2015, 2014, and 2013, the Company capitalized certain internal costs of approximately $4.5 million, $3.6 million, and $4.1 million, respectively.

Costs of acquiring unproved oil and gas properties are initially excluded from the depletable base and are assessed at each reporting period to ascertain whether impairment has occurred.  When proved reserves are assigned to the property or the property is considered to be impaired, the costs of the property or the amount of impairment is added to the depletable base.  Upon complete evaluation of a property, the total remaining excluded cost (net of any impairment) is included in the full cost amortization base.

Capitalized costs, as adjusted for estimated future development costs and estimated asset retirement costs, less estimated salvage values, are depreciated, depleted, and amortized using the units-of-production method based on estimated proved reserves as determined by petroleum engineers.  The costs of wells-in-progress and unevaluated properties, including any related capitalized interest and internal costs, are not amortized.  For the purposes of this calculation, crude oil and natural gas liquid reserves and production are converted to equivalent volumes of natural gas based on the relative energy content of one barrel to six thousand cubic feet of gas.  Proceeds from the disposal of properties are

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normally deducted from the full-cost pool without recognition of gains or losses, except under circumstances where the deduction would significantly alter the relationship between capitalized costs and proved reserves of the cost center, in which case a gain or loss is recorded.

Pursuant to the full-cost accounting rules, the Company is required to perform a “ceiling test”.  If the net capitalized cost of the Company’s oil and gas properties subject to the amortization (the carrying value) exceeds the ceiling limitation, the excess would be charged to expense.  The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related income tax effects.  The present value of estimated future net revenue is computed by applying the average first day of the month oil and gas price for the preceding 12-month period to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves, assuming the continuation of existing economic conditions.

For the year ended December 31, 2015, the carrying value of the Company’s oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation by $172.7 million.  As a result, the Company recorded an impairment of $172.7 million.  No impairment was recorded in 2014 or 2013.  The ceiling test calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter commodity prices in future quarters could result in a potentially lower ceiling value in future periods.  This could result in ongoing impairments each quarter until prices stabilize or improve.

(e) Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2015, by the year in which such costs were incurred.  Included in the $187.5 million of costs not subject to amortization are approximately $61 million that the Company deems significant related to its acquisition of properties from Chesapeake Energy in the Marcellus Shale during 2013.  The Company expects to evaluate and develop these Marcellus Shale properties over the next three to five years and to include the relevant costs in the amortization computation as such evaluation activities are completed.

(f) Joint Ventures

Certain of the Company’s oil and gas exploration and development activities are conducted jointly with others; accordingly, the consolidated financial statements reflect only the Company’s proportionate interest in such activities.

(g) Inventory

The Company’s inventory primarily comprises tubular goods and well equipment to be used in future drilling operations.  Inventory is charged to specific wells and transferred into oil and gas properties when used.  There were no material inventory write-downs for the years ended December 31, 2015 and 2014.

(h) Gas Gathering System

The Company’s gas gathering assets are held by Vista Gathering, LLC (hereinafter referred to as Vantage Midstream).  The Company has a 100% membership interest in Vantage Midstream, operates the majority of Vantage Midstream’s assets, and owns a 50% undivided working interest in such assets.  All gas transported in the gas gathering system relates to wells in which the Company and/or Vantage Energy, LLC (Vantage I), an affiliate under common management, owns a working interest and for which either the Company or Vantage I serves as operator.  Vantage Midstream also owns a 38% nonoperated interest in the Appalachia Midstream Services, Rogersville system gas gathering joint venture.  The Company and Vantage I each own a 50% undivided working interest in Vantage Midstream’s assets.

The Company’s gas gathering assets are being depreciated on the straight-line method over a 20-year useful life.  For the years ended December 31, 2015, 2014, and 2013, the Company recognized depreciation expense on its gas gathering system assets of approximately $3.0 million, $1.7 million, and $0.7 million, respectively.  Maintenance and repairs are charged to expense as incurred.  Expenditures that extend the useful lives of assets are capitalized.  When assets are retired or otherwise disposed of, the cost of the assets and the related accumulated depreciation are removed from the accounts.  Any gain or loss on retirements is reflected in other income in the year in which the asset is disposed.

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The Company reviews its long-lived assets other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered.  The Company performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets and if the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to the asset’s fair value and an impairment loss is recorded against the long-lived asset.  There have been no provisions for impairment recorded for the years ended December 31, 2015, 2014 and 2013.

(i) Water Investment

Vantage Midstream entered into a 10-year agreement for Water System Expansion and Supply with Southwestern Pennsylvania Water Authority (SPWA) on February 18, 2015.  The purpose of the agreement was to fund and assist SPWA in constructing an expansion to its water supply system; grant the Company preferred rights to water volumes for its use in its oil and gas operations; and create a repayment structure for the Company and Vantage Midstream through a surcharge applicable to all oil and gas water users.  The proposed water system improvements to be funded by the Company are estimated to be $14.7 million; however, the Company may terminate the agreement without penalty.  The surcharge in the amount of $3.50 per 1,000 gallons of water sold to oil and gas users from the system is collected by SPWA and remitted to Vantage Midstream.  The costs incurred by us are capitalized and are being amortized on a straight line basis over the life of the agreement.  Payments to Vantage Midstream from SPWA derived from surcharges paid to SPWA by third parties are applied as a recovery of capital investment for funds advanced by Vantage Midstream to expand the system, while payments to Vantage Midstream from SPWA derived from surcharges from the Company are recorded as an offset to Vantage Midstream’s cost of water.

The Company entered in a Water Services and Supply Agreement with Vantage Midstream effective May 1, 2015.  Under the agreement, Vantage Midstream will provide water services required by the Company, including the supply of water for injection and related collection, recycling, purifying, and the disposal of water after use.  Vantage Midstream is responsible for the sourcing and transportation of water as requested by the Company.  Vantage Midstream will also collect, clean, recycle, transport, and/or dispose of produced water and flow back water resulting from the Company’s operations.  The Company’s 50% undivided working interest in the profits of the water business are eliminated against the full cost pool upon consolidation.

(j) Deferred Financing Cost

Costs associated with obtaining debt financing are deferred and amortized over the term of the debt.  These costs, net of amortization, are included in other assets.

(k) Asset Retirement Obligations

Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and returning such land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount.  The liability is accreted each period and the capitalized cost is depleted as part of the full-cost pool or is depreciated as part of the gas gathering system.  Revisions to estimated asset retirement obligations result in adjustments to the related capitalized asset and corresponding liability.

(l) Commodity Derivatives

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile natural gas prices and to manage its exposure to commodity price risk.  The Company records all derivative instruments at fair value within the accompanying consolidated balance sheets.  Changes in fair value are to be recognized currently in earnings unless specific hedge accounting criteria are met.  Management has decided not to use hedge accounting under the accounting guidance for its derivatives; therefore, the changes in fair value are recognized in earnings.  The Company classifies cash payment and receipts on its derivative instruments in operating cash flows in the accompanying consolidated statements of cash flows.

(m) Revenue Recognition

The Company accounts for natural gas sales using the “entitlements method”.  Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes.  The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue.  Any amount received in excess of the Company’s share is treated as a liability.  If the Company receives less than its entitled share, the underproduction is recorded as a receivable.  The Company sells the majority of its products soon after production at various locations, including the wellhead, at which time title and risk of loss pass to the buyer.  At December 31, 2015 and 2014, the Company did not have any material gas imbalances.

The Company’s gas gathering revenue is generated from gas gathering and compressing natural gas in Pennsylvania.  The Company provides gas gathering services and compression services under fee-based arrangements.

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(n) Concentrations of Credit Risk

The Company grants credit in the normal course of business to oil and gas purchasers in the United States of America.  Collectability of the Company’s natural gas revenue is dependent upon the financial wherewithal of the Company’s purchasers, as well as general economic conditions of the industry.  To date, the Company has not had any bad debts.

Approximately, 54%, 28%, and 15% of the Company’s accounts receivable as of December 31, 2015 were due from Asset Risk Management (ARM), South Jersey, and Noble Group, respectively.

Approximately, 41%, 24%, and 24% of the Company’s accounts receivable as of December 31, 2014 were due from South Jersey Industries, Sequent Energy, and Noble Group, respectively.

Approximately, 39% and 32% of the Company’s oil and gas revenue for the year ended December 31, 2015 were generated from ARM and South Jersey, respectively.  Approximately, 51% and 48% of the Company’s oil and gas revenue for the year ended December 31, 2014 were generated from EQT Production Company and Sequent Energy, respectively.  Approximately 69% and 30% of the Company’s oil and gas revenues for the year ended December 31, 2013 was generated from EQT Production Company and Sequent Energy, respectively.

Although a substantial portion of production is purchased by these major customers, the Company does not believe the loss of any one or both customers would have a material adverse effect on our business, as other customers or markets would be accessible to us,

(o) Marketing and Gathering Costs

The Company sells its gas at the wellhead and receives payment net of gathering expenses.  Vantage Midstream gathers all gas, excluding the Appalachia Midstream Services joint venture area.  Vantage Midstream gathering fees are $0.26 per mmbtu for initial wells and $0.50 per mmbtu for subsequent wells, with a sliding scale downward to $0.25 per mmbtu based on cumulative system throughput.

(p) Impact Fees

The state of Pennsylvania imposes an impact fee on oil and gas production based on a formula applied to individual wells.  The Company classifies the impact fees within production and ad valorem taxes on the accompanying consolidated statements of operations for the years ended December 31, 2015, 2014, and 2013.

(q) Capitalized Interest

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with projects that are not subject to current depletion.  Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use.  For the years ended December 31, 2015, 2014, and 2013, the Company capitalized interest costs to unproved properties of $4.2 million, $2.7 million, and $0, respectively.

(r) Income Taxes

The Company is a multi-member limited liability company.  Accordingly, no provision for income taxes has been recorded as the income, deductions, expenses, and credits of the Company are reported on the income tax returns of the Company’s members.

The Company accounts for uncertainty in income taxes in accordance with generally accepted accounting principles, which prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing in the consolidated financial statements tax positions taken or expected to be taken on a tax return, including a decision on whether or not to file in a particular jurisdiction.  Only tax positions that meet a more-likely than-not recognition threshold at the effective date may be recognized or continue to be recognized.

Interest and penalties associated with tax positions are recorded in the period assessed as general and administrative expenses.  No interest or penalties have been assessed as of December 31, 2015.  The Company’s information returns for tax years subject to examination by tax authorities include 2012 through the current year for state and federal tax reporting purposes.

(s) New Accounting Pronouncements

The FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, in May 2014.  ASU 2014-09 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.  ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in United States GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods.  An entity should also disclose sufficient quantitative and qualitative information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers.  The new standard is

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effective for annual reporting periods beginning after December 15, 2017.  The Company will implement the provisions of ASU 2014-09 as of January 1, 2018.  The Company has not yet determined the impact of the new standard on its current policies for revenue recognition.

The FASB issued ASU No 2016-02, Leases, in February 2016.  ASU 2016-02 will require lessees to present right-of-use assets and lease liabilities on their balance sheets.  ASU 2016-02 is effective for annual and interim periods beginning January 1, 2019.  Early adoption of ASU 2016-02 is permitted.  Upon adoption of ASU 2016-02, we are required to recognize and measure leases at the beginning of the earliest period presented in our consolidated financial statements using a modified retrospective approach.  The modified retrospective approach includes a number of optional practical expedients that we may elect to apply.  We have not yet decided when we will adopt ASU 2016-02 or which practical expedient options we will elect.  We are currently evaluating and assessing the impact ASU 2016-02 will have on us and our financial statements.  As of the date of this report, we cannot provide any estimate of the impact of adopting ASU 2016-02.

The FASB issued ASU 2015-03, Interest Imputation of Interest:  Simplifying the Presentation of Debt Issuance Costs, in April 2015.  The core principle of ASU 2015-03 will require all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of debt, consistent with debt discounts.  Upon adoption of ASU 2015-03, the new standard is limited to the presentation of debt issuance costs.  The standard does not affect the recognition and measurement of debt issuance costs.  In August 2015, the FASB issued ASU 2015-15, Interest—Imputations of Interest, Subtopic 835-30, Interest (ASU 2015-15).  The guidance in ASU 2015-03 did not address the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements.  ASU 2015-15 was issued to clarify that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements.  The amendments in ASU 2015-03 should be applied on a retrospective basis and early adoption is permitted.  ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2016.  The Company will implement the provision of ASU 2015-03 as of January 1, 2016.  The Company does not believe the impact of the new standard on its presentation of debt issuance costs will have a material effect on the Company’s financial statements and related disclosures.

(2) Balance Sheet Disclosures

Accounts receivable consist of the following:

Accounts payable and accrued liabilities consist of the following:

(3) Fair Value Measurements

Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date.  The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.  Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company.  Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances.  The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

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Level 1:                                                    Quoted prices are available in active markets for identical assets or liabilities

Level 2:                                                    Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability

Level 3:                                                    Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations

The assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.  The Company’s policy is to recognize transfers in and/or out of the fair value hierarchy as of the end of the reporting period in which the event or change in circumstances caused the transfer.  The Company has consistently applied the valuation techniques discussed below in all periods presented.  The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 by level within the fair value hierarchy (in thousands):

The Company’s commodity derivative instruments consist of variable-to-fixed price swaps.  The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model.  The valuation model requires a variety of inputs, including contractual terms, published forward prices, and discount rates, as appropriate.  The Company’s estimates of fair value of commodity derivative instruments include consideration of the counterparty’s creditworthiness, the Company’s creditworthiness, and the time value of money.  The consideration of these factors results in an estimated exit price for each derivative asset or liability under a marketplace participant’s view.  All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy.  The counterparties on the Company’s derivative instruments are the same financial institutions that hold the Revolving Credit Facility (note 7).  Accordingly, the Company is not required to post collateral on these derivatives since the bank is secured by the Company’s oil and gas assets.

Non-Recurring Fair Value Measurements

The Company uses the income valuation technique using a discounted cash flow model to estimate the initial fair value of asset retirement obligations using estimated gross well costs of reclamation ranging in amounts from $10,000 to $100,000, timing of expected future dismantlement costs ranging from 20 to 28 years, and a weighted average credit-adjusted risk-free rate.  Accordingly, the fair value is based on unobservable pricing inputs and, therefore, is included within the Level 3 fair value hierarchy.  During the years ended December 31, 2015 and 2014, the Company recorded liabilities for asset retirement obligations of $0.3 million and $0.9 million, respectively.  See note 4 for additional information.

Other Financial Instruments

Other financial instruments not measured at fair value on a recurring basis include cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities.  The financial statement carrying amounts of these items approximate their fair values due to their short-term nature.

(4) Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligations associated with the retirement of oil and gas properties and the gas gathering system:

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(5) Commodity Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices.  The Company is focused on maintaining an active hedging program using commodity derivative financial instruments to achieve a more predictable cash flow by reducing its exposure to commodity price fluctuations and regional basis differential exposure in an effort to protect its capital investment program, as well as expected future cash flows.  The Company’s risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions.  The Company currently uses fixed price natural gas swaps for which it receives a fixed swap price for future production in exchange for a payment of the variable market price received at the time future production is sold.

While the use of instruments limits the downside risk of adverse price changes, their use may also limit future revenue from favorable price changes.  The Company has adopted fair value accounting for its derivatives; therefore, changes in the fair value of derivative financial instruments are recognized in earnings.  Cash payments or receipts on such contracts are included in cash flows from operating activities in the consolidated statements of cash flows.

At December 31, 2015, the terms of outstanding commodity derivative contracts were as follows:

The Company estimates that 2016 hedged volumes, in aggregate, represent approximately 63% of the Company’s estimated proved gas production for 2016, based upon the year-end external reserve report.

Depending on changes in oil and natural gas futures markets and management’s view of underlying supply and demand trends, the Company may increase or decrease its hedging positions.

The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and by counterparty.  As of December 31, 2015, the Company’s commodity derivative instruments were subject to an enforceable master netting arrangement that provides for offsetting of amounts payable or receivable between the Company and the counterparty.  The agreement also provides that in the event of an early termination, the counterparty has the right to offset amounts owed or owing under that and any other agreement with the same counterparty.  The Company’s accounting policy is to offset these positions in the accompanying consolidated balance sheets.

The following tables provide a reconciliation between the net assets and liabilities reflected in the accompanying consolidated balance sheets and the potential effects of master netting arrangements on the gross fair value of the commodity derivative contracts:

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The table below summarizes the realized and unrealized gains related to the Company’s commodity derivative instruments.  These realized and unrealized gains are recorded in the accompanying consolidated statement of operations.

Due to the volatility of oil and natural gas prices, the estimated fair values of the Company’s commodity derivative instruments are subject to large fluctuations from period to period.

(6) Related Party Transactions

(a) Gas Gathering System Operating Agreement

In connection with the Joint Development Agreement with Vantage I, the Company, through its wholly owned subsidiary, Vantage Midstream, became the operator of the gas gathering assets.  Pursuant to a Gathering System Operating Agreement, dated August 2, 2012, between the Company and Vantage I, the Company and Vantage I are to pay their respective 50% shares of the gas gathering system operating and development costs, as well as their incurred gas gathering and compression fees.  The Company was charged gas gathering and

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compression fees by Vantage Midstream of $23.9 million, $9.8 million, and $1.4 million for the years ended December 31, 2015, 2014, and 2013, respectively.

(b) Water Investment

Pursuant to the Water Services and Supply Agreement, Vantage Midstream provides water services required in the Company’s drilling operations.  The Company paid fees to Vantage Midstream of $6.5 million for the year ended December 31, 2015.  No such fees were paid in 2014 or 2013.

(c) Management Services Agreement

In August 2012, the Company and Vantage I entered into a Management Services Agreement (MSA) whereby Vantage I is to provide certain executive management, administrative, accounting, finance, engineering, land, and information technology assistance to the Company.  In exchange for providing these services, the Company will pay Vantage I a fee (the MSA Fee).  Through June 2014, the MSA Fee was calculated as 50% of the overall gross general and administrative expenses incurred by Vantage I.  Starting in July 2014, the MSA Fee is based upon the gross general and administrative expenses incurred by Vantage I multiplied by a ratio of the relative capital expenditures and oil and natural gas production volumes of the Company and Vantage I.  Certain adjustments are made to this calculation to reflect the allocation of general and administrative expenses to Vantage Midstream.  For the years ended December 31, 2015, 2014, and 2013, the Company recorded gross general and administrative expenses incurred under the MSA of approximately $12.0 million, $8.7 million, and $8.3 million, respectively.

(d) MIU Notes Receivable

In December 2014, the Company made loans to certain employees in the form of notes receivable.  Interest accrues on the notes at 0.34% per annum, and the notes mature upon the earlier to occur of:  1) December 1, 2017; 2) consummation of Monetization Event (as defined); or 3) fifteen days after the date of voluntary termination of employment by the employee or termination by the Company for cause.  As of December 31, 2015, the notes had a balance of $1.4 million and are classified in other assets in the accompanying consolidated balance sheets.  The notes are collateralized by a first lien interest in the employees’ interest in each employees’ Management Incentive Units (MIUs) and all potential dividends and distributions and a second lien on all other personal assets.  Interest income was deemed de minimus for the year ended December 31, 2015.

(e) Derivative Novations

In November 2013, the Company entered into an agreement to purchase certain derivative contracts from Vantage I, as approved by Wells Fargo Bank, N.A.  The Company determined the total fair value of the derivative contracts on the date of transfer to be approximately $1.7 million.

In January 2014, the Company entered into an agreement to purchase certain derivative contracts from Vantage I, as approved by Wells Fargo Bank, N.A.  The Company determined the total fair value of the derivative contracts on the date of transfer to be approximately $0.3 million.

(7) Long-Term Debt

(a) Revolving Credit Facility

Effective November 29, 2012, the Company secured a credit facility (the Revolving Credit Facility) with a group of bank lenders.  Wells Fargo Bank, N.A. acts as administrative agent.  Effective December 4, 2014 the Company amended and restated its Revolving Credit Facility to add a lien on the Vantage Midstream gas gathering system and add a midstream borrowing base.  The maturity date of the Revolving Credit Facility is January 1, 2017.  The Revolving Credit Facility has a maximum commitment of $500 million and as of December 31, 2015 and 2014, had a borrowing base of $166 million and $126 million, respectively.  As of December 31, 2015 and 2014, the Company had outstanding borrowings of $149 million and $100 million, respectively.  On each borrowing, the Company has the election to pay interest at a Base rate or LIBOR.  The margin on Base rate loans ranges from 0.75% to 1.75%.  The margin on LIBOR loans ranges from 1.75% to 2.75%.  The Company pays quarterly a commitment fee ranging from 0.375% to 0.50% of the unused borrowing base.  The Company elected to pay interest based on LIBOR, plus the applicable margin, which was 2.93% in total as of December 31, 2015.

As of December 31, 2015, the Revolving Credit Facility was collateralized by all of the Company’s assets, including its 50% operated interest in the Vantage Midstream assets.

The Revolving Credit Facility contains certain financial covenants, including maintenance of a minimum current ratio and a maximum leverage ratio.  As of December 31, 2015, the Company was not in compliance with the minimum current ratio covenant under the Revolving Credit Facility.  On May 10, 2016, the Company entered into the Eighth Amendment to Credit Agreement (Eighth Amendment), which included among other things, an equity cure right, applied retroactively to December 31, 2015, applicable to the Company’s covenants under its credit agreement.  The Company executed two $10 million capital calls, aggregating $20 million, from its current equity owners during the

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first four months of 2016, and such equity was included in the calculation of the current ratio covenant as of December 31, 2015, and, as a result, the Company was in compliance with all of its financial covenants as of December 31, 2015.

(b) Second Lien Term Loan

In May 2014, the Company entered into a second lien note payable (Second Lien note payable) with a face amount of $100 million, maturing on May 8, 2017.  The Company has the election to pay interest at a Base rate or Eurodollar LIBOR.  The margin on Base rate loans is 6.50%.  The margin on LIBOR loans is 7.50%.  As of December 31, 2015, the stated interest rate was 8.50%, and $100.0 million remained outstanding.  The Second Lien note payable contains an optional prepayment provision that enables the Company to prepay the Second Lien note payable at par.  The Second Lien note payable was issued with an original issue discount of $2.75 million, which has been classified as a reduction to the note balance.  The discount is amortized over the term of the note using the effective interest method.

As of December 31, 2015, the Second Lien note payable was collateralized by a second lien interest in all of the Company’s assets, including its 50% operated interest in the Vantage Midstream assets, and contains certain financial covenants.  These covenants include maintenance of a maximum leverage ratio.  As of December 31, 2015 and 2014, the Company was in compliance with this financial covenant.

During the years ended December 31, 2015, 2014, and 2013, the Company recognized gross interest expense of approximately $13.0 million, $6.7 million, and $0, respectively.

Maturities of long-term debt as of December 31, 2015 (including current maturities, excluding unamortized debt discounts) are as follows (in thousands):

(8) Commitments and Contingencies

As of December 31, 2015, the Company, as counterparty along with Vantage I, had contracts with certain rig operators and pipe suppliers totaling approximately $0.5 million of commitments for 2016.  The commitments are allocated evenly between Vantage I and Vantage II.

On April 17, 2014, the Company entered into a 20,000 Mmbtu/d firm marketing agreement to market gas production associated with volumes produced in the Marcellus Shale.  The agreement begins in October 2014 and continues through October 2020.  Under the contract, the Company is paid based on TETCO M-2 pricing with the ability to share in downstream price upside when market conditions allow.

On May 9, 2014, the Company entered into a 37,500 Mmbtu/d firm marketing agreement to market gas production associated with volumes produced in the Marcellus Shale.  The agreement began in November 2014 and continues through October 2019.  Under the contract, the Company is paid based on TETCO M-2 pricing.

From time to time, the Company is party to litigation.  The Company maintains insurance to cover certain actions and believes that resolution of such litigation will not have a material adverse effect on the Company.

(9) Capital Structure

Summarized below are the classes of interests that have been authorized:

a)                                     Class I Interest Units (Class I Units)

b)                                     Class M Management Incentive Units (Class M Units).

Effective July 29, 2012, the Members approved the Amended and Restated Limited Liability Company Agreement (the Agreement).

Class I Units

Class I Units are issued to Members from time to time in exchange for a Member’s capital commitment to make cash contributions when called by the Company pursuant to the terms as described in the Agreement.

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The Company is authorized to issue as many Class I Units as its board of managers approves.  Total capital commitments and contributions associated with outstanding Class I Units are as follows:

As of December 31, 2015 and 2014, the Company had undrawn commitments of $101.6 million and $101.7 million, respectively.  Included in the member contributions on the consolidated balance sheets are equity issuance costs of approximately $0.1 million as of December 31, 2015 and 2014.

In June 2018, all capital commitments associated with the Class I Units will be reduced to contributions made at that time.  In addition, the capital commitments of the Founders and selected other employees are subject to an additional increase of up to $7.0 million in the aggregate depending upon distributions received from Vantage I.

Decisions of the Company are approved by the majority of the Company’s board of managers.  As of December 31, 2015, the Company’s board of managers comprised eight managers, including six appointed by the Institutional Investors, and the two Founders.  One of the managers appointed by each Institutional Investor shall be subject to approval by the Founders.

Distributions of funds associated with the Class I Units follow a prescribed framework, which is outlined in detail in the Agreement.  In general, distributions are first made to those Members who have made capital contributions in accordance with sharing ratios until such Members receive distributions to meet an internal rate of return threshold of 8%.  Subsequent distributions are then allocated between the Class I and Class M Units in accordance with the provisions of the Agreement.

The Class I Units are illiquid, subject to substantial transfer restrictions, and have certain drag-along and tag-along rights as provided for in the Agreement.

The Company has the right, but not the obligation, to repurchase all of the Class I Units of management members if employment is terminated for any reason.  If employment is terminated without cause, the repurchase price of the Class I Units is based on the fair market value of the units, as defined in the Agreement.  If employment is terminated for cause, the repurchase price is equal to the lesser of i) the aggregate unreturned capital contributions and ii) the fair market value.  However, the Company option to acquire does not apply to the Founders if employment is terminated due to death or disability.  Upon termination of employment without cause or due to death or disability, the Founders/heirs may put their Class I Units of the Company at fair market value.  The put option cannot be exercised if a Founder voluntarily terminates employment or is terminated for cause.

Upon termination of employment without cause or due to death or disability, the Founders/heirs may put their Class I Units to the Company at fair market value.  Upon the occurrence of death or disability, the exercise of this put right is at the discretion of the Founders/heirs, which is an event outside of the Company’s control.  Under the standard codified within ASC 480, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” and Emerging Issues Tax Force (“EITF”) Topic D-98, stock subject to redemption requirements outside the control of the Company are required to be classified outside of permanent equity.  Accordingly, the Founders’ equity is classified outside of members’ equity.  The occurrence of these events is not deemed probable, and therefore, the Founders’ equity has been measured at historic cost.  The put option cannot be exercised if a Founder voluntarily terminates employment or is terminated for cause.

Class M Management Incentive Units

The Company has issued management incentive units to certain employees.  The management incentive units participate only in distributions in liquidation events, meeting requisite financial thresholds after Capital Interests have recovered their investment, and special allocation amounts.  Management incentive units have no voting rights.  Compensation expense for these awards will be recognized when all performance, market, and service conditions are probable of being satisfied (in general, upon a liquidating event).  Accordingly, no value was assigned to the interests when issued.

The Management Incentive Plan, as described in the Agreement, authorizes up to 2,000,000 nonvoting Class M Units.  Class M Units may be granted with an assigned participation level.

Class M Units issued to the Founders may not exceed 900,000 and vest 15% on each of the first, second, and third annual grant-date anniversaries and 100% upon consummation of a monetization event.  However, if a Founder’s employment is terminated without cause or due to death or disability, the Class M Units held will be at least 50% vested.

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The Class M Units issued to all others vest in accordance with individual grant letters, but generally require a service period of between three and five years before vesting in 45% of the Class M Units, with the remaining Class M Units vesting upon a monetization event if employed by the Company for more than one year.  All vested Class M Units shall be forfeited for no consideration if employment is terminated for cause.  All unvested Class M Units, whether to Founders or management members, shall be forfeited upon termination of employment for any reason.

The Company has the right, but not the obligation, to repurchase all of the vested Class M Units of management members if employment is terminated for any reason.  If employment is terminated without cause, the repurchase price of the Class M Units is based on the fair market value of the units, as defined in the Agreement.  However, the Company’s option to acquire the Class M Units does not apply to the Founders if employment is terminated due to death or disability.

Upon termination of employment upon death or disability, the Founders/heirs may put their Class M Units to the Company at fair market value.  The put option cannot be exercised if a Founder voluntarily terminates employment or is terminated for cause.

The following table presents the activity for Class M Units outstanding:

As of December 31, 2015 and 2014, 649,650 and 448,825, respectively, Class M Units were vested.  For financial reporting purposes, no related compensation expense has been recorded as of December 31, 2015 and 2014, as the grant-date fair value of the Class M Units was deemed immaterial.

(10) Liquidity

The Revolving Credit Facility matures on January 1, 2017.  The Company expects to repay and retire the Revolving Credit Facility in connection with the net proceeds from the completion of the public offering and cash on hand.  The Company intends the Second Lien note payable to remain outstanding following the completion of the public offering.  Additionally, the Company plans to obtain new financing following the anticipated corporate reorganization, contemporaneous with the offering.

In the event that some deficiency exists between the proceeds of the offering or the terms of the new facility and the Company’s current facility, as of December 31, 2015 the Company has available undrawn capacity under its existing borrowing base of $17 million and available undrawn capacity under its equity commitments of $102 million to address such a deficiency.  In addition, the Company expects that it will be able to secure incremental equity commitments and other sources of capital, including debt, if necessary, from its current equity investors, other investors or lenders to address any shortfall.  The Company’s current equity investors continue to be supportive of the Company’s long-term growth and financing strategy.

While we anticipate engaging in active dialogue with our creditors and the potential public offering, at this time we are unable to predict the outcome of such or whether any such efforts to raise additional equity will be successful.

(11) Supplemental Information on Gas Producing Activities (unaudited)

The following is supplemental information regarding our consolidated gas producing activities.  The amounts shown include our net working and royalty interests in all of our gas properties.

(a) Capitalized Costs Relating to Gas Producing Activities

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(b) Costs incurred in Certain Gas Activities

c) Results of Operations for Gas Producing Activities

(d) Gas Reserve Information

Proved reserve quantities are based on estimates prepared by the independent petroleum engineering firm Wright & Company for the years ended December 31, 2015, 2014, and 2013 in accordance with guidelines established by the Securities and Exchange Commission (the “SEC”).

Reserve definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC.  The reserve quantity information is limited to reserves which had been evaluated as of December 31, 2015, 2014, and 2013.  Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment.  Proved undeveloped reserves (“PUD”) are expected to be recovered from new wells after substantial development costs are incurred.  All of the Company’s proved reserves are located in the Unites States.

Proved reserves are those quantities of oil, NGLs and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that the renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonable certain that it will commence the project within a reasonable time.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures.  The estimation of our proved reserves employs one or more of the following:  production trend extrapolation, analogy, volumetric assessment and material balance analysis.  Techniques including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process.

The following table provides a rollforward of the total proved reserves for the years ended December 31, 2015, 2014, and 2013, as well as proved developed and proved undeveloped reserves at the end of each respective year:

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All of the Company’s reserves as of December 31, 2013, 2014, and 2015 were located in the Appalachian Basin.

Total proved reserves increased 346,576 MMcf in 2015 primarily due to the following:

Revisions of previous estimates Previous estimates of proved reserves were revised upward primarily attributable to technical revisions associated with PUD inventory performance after conversion to PDP as well as the base PDP reserves being revised.

Extensions and discoveries Proved reserves increased primarily attributable to increased technical certainty in areas of existing leasehold ownership, ties to internal and external development activity.

Acquisitions Proved reserves increased primarily attributable to new leasehold acquisition from third parties allowing for higher certainty in inventory development.

Total proved reserves increased 206,638 MMcf in 2014 primarily due to the following:

Revisions of previous estimates Previous estimates of proved reserves were revised upward primarily attributable to technical revisions associated with PUD inventory performance after conversion to PDP, higher pricing extending reserve life and the base PDP reserves being revised.

Extensions and discoveries Proved reserves increased primarily attributable to increased technical certainty in areas of existing leasehold ownership, tied to internal and external development activity.  Additional extensions tied to development and conversion from non-proven inventory to PDP reserves in year-end 2014.

Acquisitions Proved reserves increased primarily attributable to new leasehold acquisition from third parties allowing for higher certainty in inventory development.

Total proved reserves increased 235,433 MMcf in 2013 primarily due to the following:

Revisions of previous estimates Revisions to proved reserves were primarily attributable to increases in price; however, the Company did experience an increase due to technical revisions.

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Extensions and discoveries Extensions and discoveries during the year ended December 31, 2013 resulted primarily from new proved undeveloped locations added during the year associated with the drilling of new wells.

Acquisitions Acquisitions during the year ended December 31, 2013 resulted from properties acquired from third parties.

(e) Standardized Measure of Discounted Future Net Cash Flows

The “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves” (“Standardized Measure”) is calculated in accordance with guidance provided by FASB.  The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and gas reserves.  Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve estimates.

Under the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end reserves.  Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax flow.  Tax credits and permanent differences are also considered in the future income tax calculation.  Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The following summary sets forth the Standardized Measure (in thousands):