Exhibit 99.3

Report of Independent Registered Public Accounting Firm

The Board of Managers and Members
Vantage Energy, LLC:

We have audited the accompanying consolidated balance sheets of Vantage Energy, 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, 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.

VANTAGE ENERGY, LLC

Consolidated Balance Sheets

December 31, 2015 and 2014

(In thousands)

See accompanying notes to consolidated financial statements.

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VANTAGE ENERGY, 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, 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, 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, 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, LLC (the Company) was organized as a limited liability company under the laws of the state of Delaware in 2006.  The consolidated financial statements include the accounts of Vantage Energy, LLC and its seven 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, in various basins in the United States of America, with the primary focus on unconventional natural gas plays.

(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 the 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.  During the years ended December 31, 2015, 2014, and 2013, the Company capitalized approximately $5.3 million, $4.0 million, and $1.9 million, respectively, of certain internal costs.

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 full-cost accounting rules, the Company is required to perform a “ceiling test” calculation to test its oil and gas properties for possible impairment.  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 $344.4 million.  As a result, the Company recorded an impairment of $344.4 million.  No impairment was recognized in 2014 or 2013.  The ceiling test calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over quarter prices in future quarters is a potentially lower ceiling value each quarter.  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 $74.6 million of costs not subject to amortization are approximately $9.4 million that the Company deems significant related to its acquisition of properties from Tanglewood Exploration, LLC in the Marcellus Shale during 2012.  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 owns a 50% operated working interest in the assets of Vista Gathering, LLC (hereinafter referred to as Vantage Midstream).  All gas transported in the gas gathering system relates to wells in which the Company and/or Vantage Energy II, LLC (Vantage II), an affiliate under common management, own a working interest and for which the Company or Vantage II serves as operator.  Vantage Midstream owns and operates the majority of its gas gathering assets.  Vantage Midstream also owns a 38% nonoperated interest in the Appalachia Midstream Services joint venture for its Rogersville gas gathering system.

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, $1.6 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 asset 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 July 30, 2015.  The purpose of the agreement is to fund and assist SPWA in constructing an expansion to its water supply system; grant the Company preferred rights to water volumes for use in its oil and gas operations; and create a repayment structure for the Company 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 the Company 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 into a Water Service and Supply Agreement with Vantage Midstream effective May 1, 2015.  Under the agreement Vantage Midstream will provide 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 flowback 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 Costs

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 depreciated as part of the gathering system.  Revisions to estimated asset retirement obligations result in adjustments to the related capitalized asset and corresponding liability.

(l) Commodity Derivatives

The Company periodically uses derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price and interest rate 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 payments and receipts on its derivative instruments in operating cash flows in the accompanying consolidated statements of cash flows.

(m) Revenue Recognition

Crude oil, natural gas, and natural gas liquid (NGLs) revenue is recognized when delivery has occurred, title has transferred, and collection is probable.

The Company accounts for oil and 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 purchaser.  At December 31, 2015 and 2014, the Company did not have any material gas imbalances.

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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.

(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 oil and gas sales 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, 27%, 21%, and 9% of the Company’s accounts receivable as of December 31, 2015 were due from Chesapeake Energy, Asset Risk Management (ARM), and South Jersey, respectively.  Approximately, 27%, 19%, and 14% of the Company’s accounts receivable as of December 31, 2014 were due from ETC Marketing, Bayshore Energy, and Chesapeake Energy, respectively.

Approximately, 41%, 21%, 20%, and 11%, of the Company’s oil and gas revenue for the year ended December 31, 2015 was generated from ARM, Targa Resources, ETC Marketing, and Chesapeake Energy, respectively.  Approximately, 28%, 24%, 16%, and 13% of the Company’s oil and gas revenue for the year ended December 31, 2014 was generated from Sequent Energy, Targa Resources, ETC Marketing, and Chesapeake Energy, respectively.  Approximately, 32% and 22% of the Company’s oil and gas revenues for the year ended December 31, 2013 was generated from ETC Marketing 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 several 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

In Texas, the Company sells at the wellhead and receives payment net of gathering expenses.  In the Lake Arlington area (Tarrant County), the Company’s volumes are gathered by Summit under a long-term agreement and marketed by ETC Marketing, Ltd.  The gathering fee is $0.67/mmbtu plus 3.2% for compression and fuel.  In the Rosedale area (Tarrant County), volumes are gathered by Crestwood under a long-term agreement and marketed by ARM Energy Management.  The current gathering fee is $0.3l/mmbtu with approximately $0.20/mmbtu for compression, and 1.5% for fuel.  In the Southcliff area (Tarrant County), volumes are gathered by Access under a long-term agreement and marketed by ARM Energy Management.  The current gathering fee is $0.57/mmbtu with a 2.0% fuel charge.  The price received from these contracts is Waha index related.

The Company has multiple gathering and processing agreements for volumes produced in Denton County, Texas and Wise County, Texas.  These agreements are with Targa, Devon, and EnLink.  The average deduct from Waha for residue gas is approximately $0.40/mmbtu.  The average deduct from Mt. Belvieu for NGLs is approximately $5.10/barrel.  Field condensate is gathered and marketed by Enterprise under short-term agreement and generally receives a price of WTI less $5.00/bbl.

In Pennsylvania, Vantage Midstream gathers all gas, excluding the Appalachia Midstream Services joint venture area.  Vantage Midstream gathering fees are $0.26/mmbtu for initial wells and $0.50/mmbtu for subsequent wells, with a sliding scale downward to $0.25/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 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 $1.6 million, $1.5 million, and $2.8 million, 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 is subject to the Texas margin tax, which is generally calculated as 1% of gross margin.  The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenue and expenses.  During the years ended December 31, 2015, 2014, and 2013, the margin tax was immaterial to the consolidated financial statements.

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The Company accounts for uncertainty in income taxes in accordance with generally accepted accounting principles, which prescribe 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 2010 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 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 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:

Joint interest billings represent receivables from joint interest owners on properties the Company operates.  For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover nonpayment of joint interest billings.

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Accounts payable and accrued liabilities consist of the following:

(3) Long-Term Debt

(a) Revolving Credit Facility

Effective July 19, 2007, the Company secured a credit facility with a group of bank lenders.  Wells Fargo Bank, N.A. acts as administrative agent.  Effective December 20, 2013, the Company amended and restated its credit facility (the Revolving Credit Facility) to adjust the borrowing base, increase the maximum commitment to $750 million, and allow for the Second Lien note payable (see below).  The maturity date of the Revolving Credit Facility is January 1, 2017.  As of December 31, 2015 and 2014, the Company had a borrowing base of $276 million and $250 million, respectively.  As of December 31, 2015 and 2014, the Company had outstanding borrowings of $271 million and $192 million, respectively.  On each borrowing, the Company has the election to pay interest at a Base rate or Eurodollar 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 commitment fees ranging from 0.375% to 0.500% of the unused borrowing base.  The Company generally elects to pay interest based on LIBOR, plus the applicable margin, which was 3.18% 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, a minimum interest coverage ratio, and a minimum asset coverage 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 Fifth Amendment to the Second Amended and Restated Credit Agreement (Fifth 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 a $20 million capital call from its current equity owners during the first quarter 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 December 2013, the Company entered into a Second Lien note payable (Second Lien note payable) with a face amount of $200 million, maturing on December 20, 2018.  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%.  LIBOR has a floor of 1.00%.  As of December 31, 2015, the stated interest rate was 8.50%, and approximately $196 million was 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 $2.0 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.  The Second Lien note payable requires quarterly principal payments of $500,000, which commenced March 31, 2014.

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 minimum asset coverage ratio.  As of December 31, 2015 and 2014, the Company was in compliance with this financial covenant.

The Company recognized gross interest expense of approximately $23.7 million, $19.1 million, and $3.2 million during the years ended December 31, 2015, 2014, and 2013, respectively.

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

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(4) 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 developed 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:

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 to 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 tables present 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 counterparties’ 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.  Accordingly, the Company is not required to post collateral on these derivatives since the banks are secured by the Company’s oil and gas assets.

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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 in amounts ranging from $10,000 to $100,000, timing of expected future dismantlement costs ranging from 1 year 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 $0.6 million and $1.7 million, respectively.  See note 5 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, accrued liabilities, and long-term debt.  With the exception of long-term debt, the financial statement carrying amounts of these items approximate their fair values due to their short-term nature.

(5) 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 gathering system.

(6) 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 these 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 our consolidated statements of cash flows.

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

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The Company estimates that 2016 hedged volumes, in aggregate, represent approximately 78% of the Company’s estimated proved production for 2016, based upon the year-end external reserve report.

Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our 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.  The Company enters into derivatives under a master netting arrangement with two counterparties, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparties.

The following tables provide 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 derivative contracts:

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

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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.

(7) Related Party Transactions

(a) Gas Gathering System Operating Agreement

In connection with the Joint Development Agreement between the Company and Vantage II, Vantage Midstream became the operator of the gas gathering assets.  Pursuant to a Gas Gathering System Operating Agreement, dated August 2, 2012, between the Company and Vantage Midstream, the Company and Vantage II are to pay their respective 50% shares of the gas gathering system’s operating and development costs, as well as their incurred gas gathering and compression fees.  The Company was charged gas gathering and compression fees by Vantage Midstream of $5.4 million, $3.0 million, and $2.0 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 $4.5 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 II entered into a Management Services Agreement (MSA) whereby the Company is to provide certain executive management, administrative, accounting, finance, engineering, land, and information technology assistance to Vantage II.  In exchange for receiving these services, Vantage II will pay the Company 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 the Company.  Starting in July 2014, the MSA Fee was allocated based upon the gross general and administrative expenses incurred by the Company multiplied by a ratio of the relative capital expenditures and oil and natural gas production volumes of the Company and Vantage II.  Certain adjustments are made to this calculation to reflect the allocation of general and administrative expenses to Vantage Midstream.  The Company billed general and administrative expenses under the MSA to Vantage II of approximately $12.0 million, $8.7 million, and $8.3 million for the years ended December 31, 2015, 2014, and 2013, 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 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 January 2014, the Company entered into an agreement to transfer certain derivative contracts to Vantage II, 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.

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In November 2013, the Company entered into an agreement to sell certain derivative contracts to Vantage II, 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.

(8) Commitments and Contingencies

The Company leases office spaces in Colorado, Pennsylvania, and Texas under noncancelable operating leases that expire in 2017 and 2016, respectively.  Rent expense for the years ended December 31, 2015 and 2014 was $0.4 million and $0.3 million, respectively.  Future minimum lease payments under these leases are approximately $0.7 million for the period from November 2015 to June 2017, of which a portion will be allocated between the Company and Vantage II.

On August 22, 2008, the Company secured a letter of credit in the amount of $0.1 million with Wells Fargo Bank, N.A. in connection with the signing of an exploration agreement.  Partial draws under this letter of credit are permitted.  As of December 31, 2015, no amounts have been drawn under the letter of credit.

As part of a Founder’s employment agreement, the Company will pay $0.5 million to such Founder provided all of the following conditions have been met:

i. The Company’s invested capital equals $250 million or greater

ii. Monetization events aggregating at least $500 million in proceeds have been completed

iii. Distributions to Capital Interest Members are sufficient, in part, to exceed the Second Threshold, as defined in the LLC Agreement.

As of December 31, 2015, none of the $0.5 million has been accrued, as fulfillment of the above criteria has not been deemed probable.

Effective August 1, 2010, and amended in October 2014, the Company entered into a gas gathering agreement related to its Lake Arlington project in Tarrant County, Texas, which committed the Company to transport a minimum quantity of natural gas for seven years starting on the date gas is first delivered.  If the Company transports more than the minimum quantity, the Company will receive a credit for excess transported gas, calculated as actual quantity transported, less minimum transportation quantity, multiplied by a stated dollar amount per MMBtu.  This credit can be used to offset shortfalls incurred, if any, in the year immediately before or after the excess quantity was incurred.  As of December 31, 2015, remaining total minimum revenue commitments due over the term of the agreement aggregate to $14.8 million The portion of the remaining minimum commitment that is due in 2016 totals $0.6 million as of December 31, 2015, subject to a rollover provision in the agreement that permits the Company to roll a portion of any deficit commitment to the subsequent period.

Effective August 1, 2013, the Company entered into a gas gathering agreement related to its Wedgwood project in Tarrant County, Texas, under which the Company is required to make a minimum revenue commitment of $8.8 million over four years starting on the date gas is first delivered.  The gas gathering fee on which the minimum revenue commitment is based is $0.55 per MMBtu, and remains at that level under the agreement until the Company sells 20,000,000 MMBtu from its Wedgewood project, at which time the gas gathering fee reduces to $0.34 per MMBtu for all subsequent volumes.  As of December 31, 2015, the Company had a remaining total commitment of $4.4 million The portion of the remaining minimum revenue commitment that is due in 2016 totals $0.3 million as of December 31, 2015, subject to a rollover provision in the agreement that permits the Company to roll a portion of any deficit obligations to the subsequent period.

On April 17, 2014, the Company entered into a 20,000 MMBtu/d firm marketing agreement to market a portion of our production associated with volumes produced in the Marcellus Shale.  The agreement began 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 in a 37,500 MMBtu/d firm marketing agreement to market a portion of our 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.

As of December 31, 2015, the Company, as a counterparty along with Vantage II, had contracts with certain rig operators and pipe suppliers totaling approximately $2.3 million of commitments for 2015.

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 four classes of interests that have been authorized:

a) Capital Interests (excluding interests acquired under the Leveraged Investment Program)

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b) Class A Management Incentive Units

c) Class B Management Incentive Units

d) Class C Management Incentive Units.

Effective July 1, 2010, the Members approved the Fourth Amendment to the Company’s Limited Liability Company Agreement (the Fourth Amendment) creating the Class C Management Incentive Units.  The Company offered each holder of Class A Management Incentive Units and Class B Management Incentive Units, who was employed by the Company on July 1, 2010, the opportunity to exchange all of such Units held by such holders for new Class C Management Incentive Units.  In addition, the Fourth Amendment provided for the return of $1.4 million of capital contributions to certain Members to maintain consistent capital commitment contribution percentages among all Members.  Effective August 1, 2012, the Members entered into a Second Amended and Restated Limited Liability Company Agreement (the Agreement).

(a) Capital Interests

Capital Interests 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.

Total capital contributions and deemed commitments associated with outstanding Capital Interests are as follows:

As of December 31, 2015 and 2014, the Company had undrawn commitments of $50.9 million Member contributions on the consolidated balance sheets are net of equity issuance costs of approximately $0.4 million and $0.3 million as of December 31, 2015 and 2014, respectively.

Members are entitled to preferred distributions in an amount equal to 8% per annum.  As it relates to Class C Management Incentive Units, preferred distributions are compounded annually beginning on July 1, 2010 on the sum of $135 million plus any capital contributions made by Members subsequent to July 1, 2010.  Preferred distributions are paid only if distributable cash, as defined in the Agreement, is available.  As of December 31, 2015 and 2014, accumulated but undeclared and unpaid preferred distributions related to the Class C Management Incentive Units approximated $124.4 million and $94.2 million, respectively.

The amount of accumulated preferred distributions is also used to determine the size of any payments that may be made to holders of Management Incentive Units.  With respect to calculating payments, if any, to holders of the Class C Management Incentive Units, the actual amount of accumulated but undeclared preferred distributions with respect to the Capital Interests as described in the preceding paragraph is determinative.  For purposes of calculating payments, if any, to holders of the Class A Management Incentive Units who did not exchange their Class A Management Incentive Units for new Class C Management Incentive Units, preferred distributions are accrued from the dates that capital contributions were made to the calculation date and are based on the full amount of all such capital contributions.  As of December 31, 2015 and 2014, accumulated but undeclared and unpaid preferred distributions related to the Class A Management Incentive Units approximated $282.6 million and $229.5 million, respectively.

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 seven managers, including five appointed by the Institutional Investors, and the two Founders.  The Founders may elect to appoint an additional independent manager.

The Company has the right, but not the obligation, to repurchase all Capital Interests and vested Management Incentive Units of employee Members, who are terminated for any reason, at the Units’ estimated fair value under the conditions provided for in the Agreement, except that this right does not exist with respect to the death or disability of any Founder.  If an employee Member is terminated for cause, his or her Management Incentive Units, whether vested or unvested, will be forfeited, and his or her Capital Interests may be repurchased for the lesser of the aggregate unreturned capital contributions of such Member or fair market value.  Upon termination of employment without cause or due to death or disability, the Founders/heirs may put their Capital Interests to the Company at fair market value.  The put option cannot be exercised if a Founder voluntarily terminates employment or is terminated for cause.

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Distributions of funds associated with Capital Interests defined above 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 until such Members receive the sum of $135 million plus any additional capital contributions made subsequent to July 1, 2010 plus an 8% per annum return from July 1, 2010, as described above.  Subsequent distributions are then allocated 85% to the holders of Capital Interests in accordance with specified sharing ratios and 15% to the holders of Management Incentive Units.  The 15% incentive pool is allocated based on the number of Class C Management Incentive Units, taking into consideration payments made to holders of any remaining Class A Management Incentive Units that have not been exchanged for Class C Management Incentive Units.  In addition, depending on amounts due from or to participants in the Leveraged Investment Program, certain distributions may be made to or by such participants upon a monetization event.

The Capital Interests are illiquid and subject to substantial transfer restrictions and have certain drag-along and tag-along rights as provided with the agreement.

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.

(b) Leveraged Investment Program

Between December 18, 2006 and June 19, 2009, and at the time of employment for employees first employed between June 16, 2008 and June 17, 2009, the Company was authorized to issue to employees who are also Capital Interest Members up to $15 million of Leveraged Amounts.  The Leveraged Amounts are limited recourse notes, collateralized by both the Capital Interests acquired independently of the Leveraged Investment Program amounts and the Capital Interests acquired through the Leveraged Investment Program amounts, but otherwise nonrecourse to the Capital Interest Members.  The participants have significant capital at risk outside the Leveraged Amounts and therefore no compensation is derived from these notes.  The notes mature only upon the occurrence of a sale of the Company.

In connection with the Fourth Amendment, participants in the Leveraged Investment Program who were current employees were given the opportunity to surrender and relinquish their right to participate in the remaining undrawn portion of the Leveraged Investment Program, which represented 41.5% of such participants’ allocated Leveraged Amounts under the Leveraged Investment Program.  As of December 31, 2010, participants had surrendered the right to participate in $1.6 million aggregate Leveraged Amounts under the Plan.

The terms of the notes issued under the Leveraged Investment Program provide for interest to accrue at 5.0% per annum.  As the interest due to the Company on these notes will be withheld out of future distributions, interest income will be recognized at the time such distributions are paid.  As of December 31, 2015 and 2014, interest income accumulated, but not recognized, approximated $2.4 million and $2.0 million, respectively.  The total Leverage Investment Capital since inception through December 31, 2015 is $5.3 million.

(10) 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.

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

(a) Class A Management Incentive Units

The Management Incentive Plan, as described in the Agreement, authorizes up to 1,000,000 nonvoting, Class A Management Incentive Units.  In connection with the Fourth Amendment, holders of Class A Management Incentive Units who were employed by the Company on July 1, 2010 were offered the opportunity to exchange their Class A Management Incentive Units for newly issued Class C Management Incentive Units.  No new Class A Management Incentive Units may be issued following the Fourth Amendment.  As of December 31, 2015 and 2014, 109,171 and 110,171, Class A Management Incentive Units were outstanding, respectively.  For financial reporting purposes, no related compensation expense has been recorded as of and for the years ended December 31, 2015 and 2014.

Prior to the Fourth Amendment, certain Class A Management Incentive Units vest on a schedule of 20% at the end of each of the first four years following the date of grant, with the final 20% vesting only upon the occurrence of a sale of the Company.  Other Class A Management Incentive Units vest 100% upon the occurrence of a sale of the Company.  As of December 31, 2015 and 2014, 109,171 and 110,171 Class A Management Incentive Units were vested and outstanding, respectively.

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(b) Class B Management Incentive Units

The Management Incentive Plan, as described in the Agreement, authorizes up to 45 Class B Management Incentive Units.  In connection with the Fourth Amendment, holders of Class B Management Incentive Units were offered the opportunity to exchange their Class B Management Incentive Units for newly issued Class C Management Incentive Units.  No new Class B Management Incentive Units may be issued following the Fourth Amendment.  All holders of Class B Management Incentive Units accepted such offer; thus, at December 31, 2015 and 2014, there were no Class B Management Incentive Units outstanding.

(c) Class C Management Incentive Units

The 2010 Management Incentive Plan, as described in the Fourth Amendment, authorizes up to 1,818,182 nonvoting, Class C Management Incentive Units.  In connection with the Fourth Amendment, holders of Class A Management Incentive Units and Class B Management Incentive Units who were employed by the Company on July 1, 2010 were offered the opportunity to exchange their Class A Management Incentive Units and Class B Management Incentive Units for newly issued Class C Management Incentive Units.  Holders of 564,182 Class A Management Incentive Units exchanged such Units for 564,182 Class C Management Incentive Units, and holders of all of the 45 outstanding Class B Units exchanged such Units for 894,195 Class C Management Incentive Units.  As of December 31, 2015 and 2014, 1,630,604 and 1,698,479 Class C Management Incentive Units were outstanding, respectively.

The Class C Management Incentive Units vest on a schedule of 15% if the holder has been employed by the Company on a full-time basis for each of three, four, and five years beginning on the date of grant, with the final 55% to vest only upon the occurrence of a sale of the Company, provided that the Company gives employees up to two full years’ credit against the vesting schedule for employment prior to the date of grant.  In addition, there is accelerated vesting for each Founder of up to 50% of the Class C Management Units held by such Founder if his employment is terminated by the Company without cause.  As of December 31, 2015 and 2014, 715,909 and 675,322 Class C Management Incentive Units, respectively, were vested.

The following table presents the activity for Class C Management Incentive Units outstanding:

(11) Employee Retirement Savings Plan

The Company sponsors a qualified tax-deferred savings plan (Retirement Savings Plan) for its employees in accordance with the provisions of Section 401(k) of the Internal Revenue Code.  Employees may defer up to 80% of their compensation, subject to certain limitations.  Effective May 1, 2007, the Company’s matching percentage is up to 6% of eligible employee compensation.  For the years ended December 31, 2015, 2014, and 2013, expenses associated with the Company’s contributions to the Retirement Saving Plan totaled approximately $0.5 million, $0.4 million, and $0.1 million, respectively.  The Company matches all employee contributions in cash.

(12) Liquidity

The Revolving Credit Facility matures on January 1, 2017.  The Company expects to repay and retire the Revolving Credit Facility and the Second Lien note payable in connection with the net proceeds from the completion of the public offering and cash on hand.  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 $5 million and available undrawn capacity under its equity commitments of $51 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.

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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.

(13) Supplemental Information on Oil and Gas Producing Activities (unaudited)

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

(a) Capitalized Costs Relating to Oil and Gas Producing Activities

(b) Costs incurred in Certain Oil and Gas Activities

(c) Results of Operations for Oil and Gas Producing Activities

(d) Oil and Gas Reserve Information

Proved reserve quantities are based on estimates prepared by the independent petroleum engineering firms of Netherland, Sewell & Associates, Inc. and 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.

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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.