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Exhibit 99.3

Citrus Energy Corporation

CONSOLIDATED BALANCE SHEETS

   

The accompanying notes are an integral part of these financial statements

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Citrus Energy Corporation

CONSOLIDATED BALANCE SHEETS (Continued)

   

The accompanying notes are an integral part of these financial statements

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Citrus Energy Corporation

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31,

   

The accompanying notes are an integral part of these financial statements

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Citrus Energy Corporation

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2014

   

The accompanying notes are an integral part of these financial statements

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Citrus Energy Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31,

   

The accompanying notes are an integral part of these financial statements

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A. NATURE OF OPERATIONS AND PRESENTATION OF FINANCIAL STATEMENTS

Nature of Operations

        Citrus Energy Corporation (the "Company" or "Citrus") was incorporated in Colorado in 1990 and operates in one segment, that segment being the acquisition, exploration and development of properties for the production of crude oil and natural gas from underground reservoirs. The Company primarily owns operating interests in properties held for the production of natural gas from the Marcellus shale formation in Pennsylvania.

Presentation of Financial Statements

        The accompanying unaudited Consolidated Financial Sstatements include the accounts of Citrus Energy Corporation and its subsidiaries, Citrus Energy Appalachia, LLC ("CEA") and Phoenix Records, LLC ("Phoenix"). Intercompany transactions and account balances have been eliminated in consolidation.

        CEA began operations on July 15, 2011 when three unrelated entities contributed cash in exchange for 20,000 Class A Preferred Membership Units and Citrus contributed all of its Marcellus shale oil and gas properties and other associated assets and liabilities in exchange for 100,000 Class B Common Membership Units. On July 26, 2013, all of the Class A Preferred Membership Units were retired. Thereafter, CEA is solely owned by Citrus.

        CEA owns 87.5% of the membership interests of Phoenix. Phoenix owns undeveloped Marcellus shale oil and gas properties.

Interim Financial Information

        The accompanying unaudited Consolidated Financial Statements have been prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP) and with the instructions to Article 10 of Regulation S-X for interim financial information. Accordingly, these statements do not include all of the information and notes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited Consolidated Financial Statements include all adjustments, consisting of normal recurring items, necessary for their fair presentation in conformity with GAAP. Interim results are not necessarily indicative of results for a full year.

Use of Estimates

        The preparation of the Consolidated Financial Statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dated of the Consolidated Financial Statement, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

B. CREDIT FACILITIES

        The Company's credit facilities at March 31, 2014 consist of a $250 million revolving credit facility and term loan credit facilities totaling $195 million.

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

B. CREDIT FACILITIES (Continued)

Revolving Credit Facility

        On July 26, 2013, CEA entered into a $250,000,000 senior secured revolving credit facility with Bank of Montreal as administrative agent, and other lenders party thereto. Borrowings under the credit facility are secured by first liens on substantially all of CEA's properties and assets and are further guaranteed by Citrus. Borrowed funds may be paid down and re-borrowed during the term of the revolver. The credit facility matures on July 26, 2017.

        Borrowings under the credit facility are subject to a borrowing base limitation that is redetermined semi-annually and that takes into account CEA's natural gas properties, reserves, total indebtedness, and other relevant factors consistent with customary oil and gas lending criteria. The borrowing base as of March 31, 2014 was $45,000,000.

        Based on the CEA's election, interest is payable at a rate consisting of either an adjusted LIBOR rate or an alternate base rate, plus an applicable margin. The applicable margin varies from 1.75% to 2.75% for Eurodollar-based loans or from 0.75% to 1.75% for alternate base rate loans. The applicable margin is based on CEA's utilization of the credit facility at the time of borrowing. Commitment fees are due quarterly at a rate of 0.50% of the unused portion of the borrowing base.

        As of March 31, 2014, the outstanding balance under the credit facility was $20,000,000, with a weighted average interest rate of 2.22%. There were no outstanding letters of credit under the credit facility.

        The credit facility contains customary representations, warranties and covenants, including restrictions on indebtedness and distributions, and the following financial covenants with respect to CEA:

•

the ratio of all indebtedness to EBITDAX shall be less than 4.0 to 1.0,



•

the ratio of current assets (excluding derivative contracts) plus the unused commitment under the credit facility to current liabilities (excluding derivative contracts) shall be more than 1.0 to 1.0, and



•

the ratio of the present value of proved reserves to net secured debt shall be more than 1.5 to 1.0.

        CEA was in compliance with all covenants as of March 31, 2014.

Term Loan Credit Facilities

        On July 26, 2013, CEA entered into a $175,000,000 term loan credit facility with Natixis, New York Branch as administrative agent, and other lenders party thereto. On August 28, 2013, an incremental first amendment was executed establishing a $20,000,000 incremental term loan credit facility. Net proceeds from the facilities were approximately $165,220,000 and $18,769,000, respectively, after deducting expenses and original issue discounts of 3.3% and 4%, respectively. Borrowings under the credit facilities are secured by second liens on substantially all of CEA's properties and assets and are further guaranteed by Citrus.

        Based on the CEA's election, interest is payable at a rate consisting of either an adjusted LIBOR rate or an alternate base rate, plus an applicable margin. The applicable margin is 8.50% for

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

B. CREDIT FACILITIES (Continued)

Eurodollar-based loans or 7.50% for alternate base rate loans. The total interest rate was 9.75% at March 31, 2014.

        The Company may prepay all or part of the outstanding principal at any time between July 27, 2014 and July 26, 2015, at a redemption price of 101 and thereafter at par. Mandatory prepayments are required upon the consummation of certain asset dispositions or the issuance of certain indebtedness.

        The credit facilities contain customary representations, warranties and covenants, including restrictions on indebtedness and distributions, and a financial covenant that CEA's ratio of the present value of proved reserves to net secured debt shall not be less than 1.5 to 1.0. CEA was in compliance with all covenants as of March 31, 2014.

        As of March 31, 2014, the outstanding balance under the credit facilities was $188,394,881, net of unamortized discounts of $5,630,119. The facilities mature on July 26, 2018. Aggregate principal maturities, excluding discounts, are as follows:

C. PRICE RISK MANAGEMENT

        The Company is exposed to market risks related to the price volatility of natural gas. The Company periodically uses commodity derivative contracts to reduce the effect of price changes on a portion of its future natural gas production, achieve more predictable cash flows in an environment of volatile gas prices and manage its exposure to commodity price risk. These derivative contracts limit the downside risk of adverse price movements but also may limit the Company's ability to benefit from favorable price movements. From time to time, the Company may restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of its existing contracts. All derivative contracts that the Company enters into are at no up-front cost to the Company. Management has assessed the credit risk of these contracts to be minimal and does not require collateral or other security. Similarly, no counterparty has required the Company to provide any form of security guarantee specific to these contracts. The Company does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features.

        Derivative contracts are carried at fair value on the consolidated balance sheets as assets or liabilities. At March 31, 2014 and December 31, 2013, the Company's derivative contract assets and

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

C. PRICE RISK MANAGEMENT (Continued)

liabilities were as shown below. The fair value of open contracts is not necessarily indicative of the actual gains or losses that will be realized upon future settlement of the contracts.

        The Company's derivative contracts have not been designated as hedges for accounting purposes; therefore, the changes in the fair value are included in the consolidated statements of operations for the period in which the change occurs. For the three months ended March 31, 2014 and 2013, the Company recognized net gains (losses) as follows:

        The Company's credit facilities require it to periodically meet certain minimum levels (based on percentages of projected production volumes) of hedged volumes for a forward period of three years, but not extending past the maturity date of the facilities. The Company was in compliance with this requirement at March 31, 2014. The following table summarizes the Company's open natural gas derivative contracts as of March 31, 2014.

D. COMMITMENTS AND CONTINGENCIES

Transportation and Gathering Agreements

        The Company has entered into certain natural gas transportation and gathering agreements with various pipeline carriers. Under certain of these agreements, the Company is obligated to transport minimum daily quantities, or pay for any deficiencies at a specified rate. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

D. COMMITMENTS AND CONTINGENCIES (Continued)

systems regardless of the amount of pipeline capacity utilized by the Company. In most cases, the Company's production commitment to these pipelines is expected to exceed minimum daily quantities provided in the agreements. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability.

E. SUPPLEMENTAL CASH FLOW INFORMATION

        The Company's supplemental cash flow information for the three months ended March 31, 2014 and 2013, is as follows:

F. SUBSEQUENT EVENTS

        On July 6, 2014, CEA entered into a Purchase and Sale Agreement (the "Agreement") with Warren Resources, Inc. ("Warren"). Under the terms of the Agreement, Warren will acquire substantially all of CEA's assets except that CEA will retain a 25% working interest in the Upper Marcellus shale formation in Wyoming County, Pennsylvania. The Agreement provides for a July 1, 2014 effective date. The total consideration to be received by CEA, subject to certain post-closing adjustments, is $314.5 million, consisting of $274.5 million of cash and $40 million of Warren common stock valued at $6.00 per share. CEA will have earn out rights for additional proved reserves and realized price differentials capped at an additional $8.5 million. Warren will also provide CEA with a $3.5 million carry for wells drilled in the Upper Marcellus formation.

        Management has evaluated subsequent events through July 6, 2014.

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INDEPENDENT AUDITORS' REPORT

TO THE STOCKHOLDERS

Citrus Energy Corporation
Castle Rock, Colorado

Report on the Financial Statements

        We have audited the accompanying consolidated financial statements of Citrus Energy Corporation, which comprise the balance sheets as of December 31, 2013 and 2012, and the related consolidated statements of operations, changes in equity, and cash flows for each of the three years ended December 31, 2013, 2012 and 2011, and the related notes to the consolidated financial statements.

Management's Responsibility for the Financial Statements

        Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility

        Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement.

        An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

        We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Citrus Energy Corporation as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years ended December 31, 2013, 2012, and 2011, in conformity with accounting principles generally accepted in the United States of America.

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Other Matters

Prior Period Adjustment

        As discussed in Note K to the consolidated financial statements, during 2013, Company management changed their method of accounting for certain transactions. Accordingly, retained earnings as of December 31, 2012 and 2011, has been restated to reflect the change in accounting method.

Supplementary Information

        Our audits were conducted for the purpose of forming an opinion on the consolidated financial statements as a whole. The accompanying supplementary information is presented for purposes of additional analysis and is not a required part of the financial statements. Such information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the consolidated financial statements. The information has been subjected to the auditing procedures applied in the audit of the consolidated financial statements and certain additional procedures, including comparing and reconciling such information directly to the underlying accounting and other records used to prepare the consolidated financial statements or to the consolidated financial statements themselves, and other additional procedures in accordance with auditing standards generally accepted in the United States of America. In our opinion, the information is fairly stated in all material respects in relation to the consolidated financial statements as a whole.

/s/ Richey May & Co.

Englewood, Colorado
April 28, 2014

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CITRUS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

   

The accompanying notes are an integral part of these financial statements

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CITRUS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31,

   

The accompanying notes are an integral part of these financial statements

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CITRUS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

   

The accompanying notes are an integral part of these financial statements

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CITRUS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31,

   

The accompanying notes are an integral part of these financial statements

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A. NATURE OF OPERATIONS AND PRESENTATION OF FINANCIAL STATEMENTS

Nature of Operations

        Citrus Energy Corporation (the "Company" or "Citrus") was incorporated in Colorado in 1990 and operates in one segment, that segment being the acquisition, exploration and development of properties for the production of crude oil and natural gas from underground reservoirs. The Company primarily owns operating interests in properties held for the production of natural gas from the Marcellus shale formation in Pennsylvania.

Presentation of Financial Statements

        The consolidated financial statements include the accounts of Citrus Energy Corporation and its subsidiaries, Citrus Energy Appalachia, LLC ("CEA") and Phoenix Records, LLC ("Phoenix"). Intercompany transactions and account balances have been eliminated in consolidation.

        CEA was formed on June 30, 2011 and began operations on July 15, 2011 when a) three unrelated entities contributed an aggregate amount of $20,000,000 in cash in exchange for 20,000 Class A Preferred Membership Units, and b) Citrus contributed all of its Marcellus shale oil and gas properties and other associated assets and liabilities, including the credit facility discussed in Note F, in exchange for 100,000 Class B Common Membership Units. The holders of the Class A Preferred Membership Units were also the lenders party to the 2011 revolving credit facility discussed in Note F. On July 26, 2013, all of the Class A Preferred Membership Units were retired by the payment of an aggregate amount of $29,656,244 to the Class A members. From its inception to July 26, 2013, the profits and losses of CEA were allocated to the members in a manner that caused their capital accounts to equal, as nearly as possible, the amount the members would have received if the net book value of CEA had been distributed to the members as prescribed by the membership agreement. Thereafter, CEA is solely owned by Citrus.

        CEA owns a majority of the membership interests of Phoenix. Phoenix owns undeveloped Marcellus shale oil and gas properties. In 2012, CEA paid $50,000 to purchase another member's 7.5% interest in Phoenix. This transaction increased CEA's membership interest to 87.5%.

B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting

        The financial statements of the Company are prepared on the accrual basis of accounting.

Use of Estimates

        The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reporting of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reporting of revenue and expenses during the reporting period. Actual results could differ from those estimates and assumptions. Estimates of oil and gas reserve quantities provide the basis for the calculations of depletion, depreciation, amortization, and impairment, which represent significant components of the consolidated financial statements.

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Cash and Cash Equivalents

        Cash consists of all cash balances and highly liquid investments with an original maturity of three months or less. The Company periodically maintains cash in financial institutions in excess of FDIC limits. The Company evaluates the creditworthiness of these financial institutions in determining the risk associated with these deposits.

Restricted Certificates of Deposit

        The Company's certificates of deposit are restricted under various agreements.

Accounts Receivable

        The Company records oil and gas revenue from third parties at its net revenue interest. Oil and gas revenue receivable is the amount of gross sales of natural gas produced prior to year-end but not remitted to the Company until after year-end. Oil and gas receivables are generally unsecured.

        The Company is the operator of all of the oil and gas properties in which it owns a material interest. Oil and gas joint interest billings consist of receivables from joint interest owners for their portion of disbursements made by the Company for direct costs and overhead associated with oil and gas properties that it operates. These receivables are subject to collection under operating agreements that generally allow the right to offset future revenues against unpaid charges related to the operated wells and that also generally provide lien rights.

        Management periodically reviews accounts receivable for collectability and records an allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables at December 31, 2013 or 2012, as all material amounts are expected to be collectible.

Derivative Contracts

        The Company enters into derivative contracts, typically fixed price swaps and costless collars, to manage its exposure to commodity price risk. Derivative contracts are not used for speculative purposes. All derivatives contracts are recognized on the consolidated balances sheets at fair value. Although the Company does not designate any of its derivative contracts as cash flow hedges, such derivative contracts provide an economic hedge of its exposure to natural gas price risk associated with a portion of its projected future gas production. These contracts are accounted for using the mark-to-market accounting method and accordingly, the Company currently recognizes in earnings all realized and unrealized gains and losses. The resulting cash flows are reported as cash flows from operating activities.

Other Property and Equipment

        Acquisitions and improvements of office equipment, software and other property are capitalized at cost; maintenance and repairs are expensed as incurred. Depreciation is calculated using the straight-line method over the assets' estimated useful lives of 3-7 years. When assets are sold, retired, or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and a gain or loss is recognized.

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Fair Value Disclosures

        The Company follows the authoritative accounting guidance for measuring fair values of assets and liabilities in financial statements. Fair value is the price that would be received upon sale of an asset or paid upon transfer of a liability in an orderly transaction between market participants at the measurement date and in the principal or most advantageous market for that asset or liability. The fair value is calculated based on assumptions that market participants would use in pricing the asset or liability, not assumptions specific to the Company. The authoritative guidance establishes a hierarchy that prioritizes the inputs to valuation techniques. The following summarizes the fair value hierarchy:

        Level 1 Inputs—Unadjusted quoted market prices for identical assets and liabilities in an active market that the Company has the ability to access.

        Level 2 Inputs—Inputs that are observable either directly or indirectly, other than quoted market prices included in Level 1.

        Level 3 Inputs—Inputs based on prices or valuation techniques that are both unobservable and significant to the overall fair value measurement.

        The carrying amount of cash and cash equivalents, certificates of deposit, oil and gas revenue receivable and payable, and other receivables and payables are estimated to approximate their fair values due to the short maturities of these instruments.

        Derivative contracts are carried at fair value. Valuation models used to measure the fair value of these contracts consider various inputs including quoted current and forward prices for commodities, time value, volatility and other relevant economic measures. Although the fair value of the Company's derivative contracts is measured using public indices, the contracts themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these contracts as Level 2.

        The Company's long-term debt obligations bear interest at floating or approximate market rates, therefore carrying amounts and fair values are approximately equal.

        When events and circumstances indicate a significant decline in the recoverability of an oil and gas property, the Company estimates the future cash flows expected in connection with the property and compares such future cash flows to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management's expectations for the future and include significant Level 3 assumptions associated with estimates of future oil and gas production, commodity prices, operating and development costs, and a risk-adjusted discount rate.

        The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives.

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Oil and Gas Activities

        The Company uses the successful efforts method of accounting for its oil and gas producing activities. Under this method of accounting, the costs to acquire oil and gas properties, to drill and complete successful exploratory wells, to drill and complete development wells, and to install production and related facilities are capitalized when incurred. An allocated portion of general and administrative costs are also capitalized in oil and gas properties on the consolidated balance sheets. Such costs were $1,587,600 and $1,467,100 for the years ended December, 31, 2013 and 2012, respectively.

        The Company invests in unevaluated oil and gas properties for the purpose of future exploration and development of proved reserves. The costs of unproved leases which become productive are reclassified to proved properties when proved reserves are discovered on the property. Unproved oil and gas interests are carried at the lower of cost or estimated fair market value and are not subject to amortization.

        The costs of exploratory wells are capitalized pending determination of whether the well has found proved reserves. The cumulative cost of such wells as of year-end is reported on the accompanying consolidated balance sheets as wells in progress. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. Other exploration costs, including geological and geophysical costs and the costs of carrying and retaining unproved leaseholds, are expensed as incurred.

        Depreciation, depletion and amortization of capitalized costs for producing oil and gas properties is calculated using the units-of-production method, based on proved oil and gas reserves as estimated by an independent firm of petroleum engineers.

        The Company reviews the carrying values of its proved and unproved oil and gas properties annually or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted cash flows is less than the carrying value of the property, the carrying value is written down to its estimated fair value.

        Income from the sale of oil and gas production, net of royalties, is recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has been transferred and if collectability of the revenue is probable.

        Costs to operate and maintain wells and field equipment are expensed when incurred. Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future income generation are capitalized.

        Gains or losses are reflected in income upon the sale or abandonment of an entire or partial interest in oil and gas properties.

        Oil and gas revenue payable consists of amounts owed to joint interest owners for their portion of oil and gas revenue from properties operated by the Company.

Asset Retirement Obligations

        Legal obligations associated with the retirement of long-lived assets result from the acquisition, construction, development and normal use of the asset. The Company's asset retirement obligations

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

relate to the retirement of oil and gas properties and related production facilities, lines and other equipment used in field operations. The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred and increases due to the passage of time until the obligation is settled. The fair value of the liability is added to the carrying amount of the associated asset and is depreciated over the life of the asset. Management estimates that the Company's asset retirement obligations as of December 31, 2013 are not material.

Advances from Joint Interest Owners

        The Company has received deposits from third party working interest owners representing prepayments of the expected capital expenditures for various well costs. The unexpended portion of the deposits was $799,109 and $3,210,591 at December 31, 2013 and 2012, respectively.

Revenue Recognition

        Natural gas and crude oil sales result from interests in oil and gas properties owned by the Company. Sales are recognized when the product is produced and delivered and title transfers to the purchaser. Payment is generally received in the month following the date of sale. The Company does not maintain any inventory of produced gas or oil.

Income Taxes

        The stockholders of the Company have elected to be taxed under Subchapter S of the Internal Revenue Code. Accordingly, the Company's taxable income is required to be reported in the stockholders' individual income tax returns. Therefore, the accompanying financial statements do not include any provision for federal or state income taxes. Income taxes paid by the Company on behalf of the stockholders are reflected as distributions. The Company's open tax years subject to review by taxing authorities include 2012, 2011, and 2010.

Earnings per Share

        Earnings per share is computed by dividing net income (loss) attributable to Citrus stockholders by the weighted average number of outstanding shares for the period. There are no potentially dilutive securities or other contracts.

Reclassifications

        Certain amounts in the prior year's financial statements have been reclassified to conform to their presentation in the current year's statements.

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

C. OIL AND GAS ACTIVITIES

Acquisitions of Oil and Gas Properties

        During 2013 and 2012, the Company's acquisitions of oil and gas properties primarily consisted of additional leasehold interests within the boundaries of its Ardent II property located in northeastern Pennsylvania. There were no significant acquisitions in 2012. Effective July 1, 2013, Citrus increased its working interest share of the Ardent II property by purchasing 70% of the working interest of another company and the entire working interest of two individuals. The aggregate purchase price for the three transactions was $42,820,000. As a result of the three purchases, Citrus' average working interest over the entire property increased by approximately 17%.

        On July 26, 2013, a net profits interest ("NPI") that burdened all of the Company's oil and gas properties was terminated. The NPI was owned by Wells Fargo Energy Capital, Inc. as administrative agent for lenders party to the 2011 revolving credit facility discussed in Note F. The NPI was terminated concurrent with the termination of the credit facility and the retirement of CEA's Class A Preferred Membership Units, as discussed in Note A. NPI payments were to begin upon the earlier of (a) the date when CEA paid and discharged all of its obligations under the credit facility or (b) January 14, 2014. Thereafter, the NPI remained payable throughout the term of the underlying oil and gas leases. The NPI was to be 40% until the rate of return on the credit facility exceeded 20% and the return on investment of the Class A Preferred Members exceeded 1.25. Thereafter, the NPI was to be 10%. A total of $33,843,756 was paid to terminate the NPI. That amount was capitalized to CEA's proved oil and gas properties.

Exploration and Development Activities

        During 2013 and 2012, the Company's operated exploration and development activities were conducted in its Ardent II property where, as of December 31, 2013, the Company had successfully drilled and completed 27 horizontal gas wells (four wells in 2010, ten wells in 2011, four wells in 2012, and nine wells in 2013). Additionally, four other wells were drilled in 2013 and are planned for completion in 2014.

        During 2013, the Company also incurred $356,100 of capitalized costs for its participation in two non-operated wells that are adjacent to its Ardent II property. Both of those wells were in progress at December 31, 2013.

        Exploration expense for the years ended December 31, 2013, 2012 and 2011 was none, $503,844 and $1,618,177, respectively. The 2012 expense related to the plugging and abandonment of an unproductive well drilled in 2009. The 2011 expense consisted primarily of seismic surveys conducted on the Ardent II property.

Gas Gathering

        In 2010, Citrus entered into a 15 year agreement with a company (the "Gatherer") that will exclusively provide the services of gathering natural gas produced from wells in the Company's Ardent II property and processing such gas for delivery into a local distribution pipeline system (see Gas Transportation below). Among other things, the agreement specifies the fees to be paid by Citrus to the Gatherer for those services. The fees consist of a) monthly amounts computed at various rates based on gas volumes produced, and b) other amounts as described in the following paragraph. The

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CITRUS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

C. OIL AND GAS ACTIVITIES (Continued)

fees are included in oil and gas production expense in the accompanying consolidated statements of operations.

        The agreement requires the Gatherer to construct additional gathering lines and facilities as new wells are drilled and put into production by Citrus. Construction of ten gathering lines was completed and no further gathering lines are expected to be constructed. For each of the ten completed gathering lines, Citrus was required to pay Gatherer an amount equaling 135% of Gatherer's out-of-pocket construction costs with such amount payable in 30 equal monthly installments. Effective December 31, 2013, the agreement was amended to eliminate all remaining monthly payments for each constructed gathering line and instead, beginning January 2014, Citrus, as operator, is required to pay to Gatherer a) a demand fee of $92,000 per month payable for 35 months, and b) a commodity fee of $0.055 per Mcf until 150 Bcf of gas has been delivered. Citrus' share of the fees will vary each month but will approximate $69,600 per month and $0.041 per Mcf, respectively. The present value of Citrus' share of projected future payments is recorded as a deferred gathering fees asset and as corresponding deferred gathering fees payable. The deferred gathering fees asset is amortized to production expense over the remaining term of the agreement using the units of production method while the deferred gathering fees payable is reduced as the demand fee and commodity fee payments are made to Gatherer.

Gas Transportation

        Citrus has a long-term contract with a pipeline company (the "Transporter") through November 2028. The contract provides that Citrus will exclusively utilize Transporter's pipeline system for the transportation of natural gas from the terminus of the gathering system discussed above to two interstate gas pipelines and a commercial manufacturing plant owned by Procter & Gamble Paper Products Company ("P&G"). Transporter's system has a maximum capacity of 285,000 dekatherms per day. Management believes that is sufficient for the sale of all gas produced from Citrus' Ardent II property.

        The contract has a total firm commitment of 165,000 dekatherms per day consisting of 120,000 dekatherms per day committed to the interstate pipelines and 45,000 dekatherms per day to P&G's plant. No fees are payable with respect to gas transported to the plant. Citrus, as operator, pays a fixed demand fee of $1,241,004 per month for gas transported to the interstate pipelines in any amount up to 120,000 dekatherms per day. Additionally, and subject to the availability of system capacity, there is a monthly fee of $0.34 per dekatherm for amounts over 120,000 dekatherms per day. As the primary working interest owner in Ardent II, approximately 65% of all transportation fees are attributable to Citrus.

        Included in other income for the year ended December 31, 2013, is $1,480,000 of liquidated damages received by Citrus from Transporter due to its failure to complete, by a contractually obligated deadline, the construction of an extension of the transportation system to the second interstate pipeline. No further damages will be received by Citrus as the extension was completed after the deadline and put in service in November 2013.

Gas Sales and Major Purchasers

        For the years ended December 31, 2013, 2012 and 2011, 100% of the Company's oil and gas revenue was derived from the sale of natural gas produced entirely from the Marcellus shale formation

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

C. OIL AND GAS ACTIVITIES (Continued)

in northeastern Pennsylvania. The gas was sold to purchasers through a single gas marketing company. The Company had major purchasers of its gas as follows:

        The Company has a long-term contract with P&G (Purchaser A above) to supply all of the natural gas requirements of a manufacturing plant that it operates on the Ardent II property. The plant currently utilized approximately 38 MMcf of gas per day. The contract is effective until June 10, 2015, and the sales price is fixed at the posted NYMEX monthly settlement price plus $0.03 per MMBtu. Management believes there are sufficient available reserves to meet the Company's supply commitment under this contract.

        The Company is subject to credit risk associated with the gas marketing company and with the purchasers of its natural gas. Exposure to this credit risk is controlled through monitoring procedures by the Company's management. Collateral is not required and interest is not accrued. Management does not believe that the loss of its gas marketing company or purchasers would have a material adverse effect because alternatives are readily available.

Expiration and Impairment of Oil and Gas Properties

        Impairment expense of $5,356,813, $2,097,000 and none was recorded for the years ended December 31, 2013, 2012 and 2011, respectively. The impairments related to unproved properties that, because of short remaining lease terms or other reasons, management considered unlikely to be successfully developed or sold.

        During 2013 and 2012, various unproved oil and gas leases expired. The leases comprised several small prospects in western Pennsylvania and part of a prospect in eastern Pennsylvania. At the time of their expirations, the leases' cost, as reduced by previously recorded impairments, was written off. The resulting net book value charged to expense was $1,489,455, $725,796 and none for the years ended December 31, 2013, 2012 and 2011, respectively.

        The above impairment expense and expired leases are included on the consolidated statements of operations in expiration and impairment of unproved properties.

Dispositions of Oil and Gas Properties

        During 2013, the Company did not sell any of its oil and gas properties. During 2012, Phoenix sold its mineral rights in a small parcel in northern Pennsylvania and recognized a gain of $84,024.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

C. OIL AND GAS ACTIVITIES (Continued)

        During 2011, the Company entered into several transactions for the disposition of oil and gas properties resulting in recognized gains totaling $4,831,812. The major transactions are summarized as follows:

•

The Company sold its entire working interest in two prospects in western Pennsylvania for cash proceeds of $2,432,762 at a gain of $438,071.



•

The Company exchanged all of its interest in 2,658 undeveloped gross leasehold acres in northeastern Pennsylvania and received an interest in 2,591 undeveloped gross leasehold acres also in northeastern Pennsylvania. No cash was involved in the transaction. Management determined that the fair market value of the acres received exceeded the capitalized cost of the acres relinquished and accordingly recognized a gain of $3,830,414.



•

The Company exchanged all of its interest in 469 undeveloped gross leasehold acres in northeastern Pennsylvania and received an interest in 402 undeveloped gross leasehold acres also in northeastern Pennsylvania. No cash was involved in the transaction. Management determined that the fair market value of the acres received exceeded the capitalized cost of the acres relinquished and accordingly recognized a gain of $531,572.

D. ADVANCES TO STOCKHOLDER AND EMPLOYEE

        As of December 31, 2013 and 2012, the Company had made advances to a stockholder and an employee as shown below.

E. OVERPAYMENT OF JOINT INTEREST BILLING

        In November 2006 and January 2007, Citrus received from one of its then joint interest owners duplicate payments of joint interest billings that had previously been paid. The overpayments totaled $1,145,706 and at December 31, 2013 and 2012, that amount had not been repaid to the joint interest owner and was reflected as a liability on the accompanying consolidated balance sheets.

F. CREDIT FACILITIES

        The Company's credit facilities at December 31, 2013 consist of a $250 million revolving credit facility and term loan credit facilities totaling $195 million. These facilities replaced the 2011 revolving credit facility.

2013 Revolving Credit Facility

        On July 26, 2013, CEA entered into a $250,000,000 senior secured revolving credit facility with Bank of Montreal as administrative agent, and other lenders party thereto. Borrowings under the credit

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

F. CREDIT FACILITIES (Continued)

facility are secured by first liens on substantially all of CEA's properties and assets and are further guaranteed by Citrus. Borrowed funds may be paid down and re-borrowed during the term of the revolver. The credit facility matures on July 26, 2017.

        Borrowings under the credit facility are subject to a borrowing base limitation that is redetermined semi-annually and that takes into account CEA's natural gas properties, reserves, total indebtedness, and other relevant factors consistent with customary oil and gas lending criteria. The borrowing base as of December 31, 2013 was $40,000,000.

        Based on the CEA's election, interest is payable at a rate consisting of either an adjusted LIBOR rate or an alternate base rate, plus an applicable margin. The applicable margin varies from 1.75% to 2.75% for Eurodollar-based loans or from 0.75% to 1.75% for alternate base rate loans. The applicable margin is based on CEA's utilization of the credit facility at the time of borrowing. Commitment fees are due quarterly at a rate of 0.50% of the unused portion of the borrowing base.

        As of December 31, 2013, the outstanding balance under the credit facility was $14,000,000, with a weighted average interest rate of 2.24%. There were no outstanding letters of credit under the credit facility.

        The credit facility contains customary representations, warranties and covenants, including restrictions on indebtedness and distributions, and the following financial covenants with respect to CEA:

•

the ratio of all indebtedness to EBITDAX shall be less than 4.0 to 1.0,



•

the ratio of current assets (excluding derivative contracts) plus the unused commitment under the credit facility to current liabilities (excluding derivative contracts) shall be more than 1.0 to 1.0, and



•

the ratio of the present value of proved reserves to net secured debt shall be more than 1.5 to 1.0.

        CEA was in compliance with all covenants as of December 31, 2013.

Term Loan Credit Facilities

        On July 26, 2013, CEA entered into a $175,000,000 term loan credit facility with Natixis, New York Branch as administrative agent, and other lenders party thereto. On August 28, 2013, an incremental first amendment was executed establishing a $20,000,000 incremental term loan credit facility. Net proceeds from the facilities were approximately $165,220,000 and $18,769,000, respectively, after deducting expenses and original issue discounts of 3.3% and 4%, respectively. Borrowings under the credit facilities are secured by second liens on substantially all of CEA's properties and assets and are further guaranteed by Citrus.

        Based on the CEA's election, interest is payable at a rate consisting of either an adjusted LIBOR rate or an alternate base rate, plus an applicable margin. The applicable margin is 8.50% for Eurodollar-based loans or 7.50% for alternate base rate loans. The total interest rate was 9.75% at December 31, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

F. CREDIT FACILITIES (Continued)

        The Company may prepay all or part of the outstanding principal at any time between July 27, 2014 and July 26, 2015, at a redemption price of 101 and thereafter at par. Mandatory prepayments are required upon the consummation of certain asset dispositions or the issuance of certain indebtedness.

        As of December 31, 2013, the outstanding balance under the credit facilities was $188,535,118, net of unamortized discounts of $5,977,382. The facilities mature on July 26, 2018. Aggregate principal maturities, excluding discounts, are as follows:

        The credit facilities contain customary representations, warranties and covenants, including restrictions on indebtedness and distributions, and a financial covenant that CEA's ratio of the present value of proved reserves to net secured debt shall not be less than 1.5 to 1.0. CEA was in compliance with all covenants as of December 31, 2013.

2011 Revolving Credit Facility

        On January 14, 2011, the Company entered into a $150,000,000 senior secured revolving credit facility with Wells Fargo Energy Capital, Inc. ("WFEC") as administrative agent, and other lenders party thereto. On July 15, 2011, the credit facility was amended and restated to designate CEA as the borrower.

        CEA's borrowings could not exceed a borrowing base amount primarily based on the loan value of CEA's proved oil and gas reserves. At December 31, 2012, CEA's borrowing base was $83,000,000 and the outstanding amount was $65,821,651. On July 26, 2013, the outstanding principal amount was $67,585,847. On that date, utilizing funds obtained from a new term loan credit facility, CEA terminated the 2011 revolving credit facility by payment of all outstanding principal and accrued interest.

        Interest was charged at 8% throughout the term of the facility. Total interest expense on the credit facility for the years ended December 31, 2013, 2012 and 2011 was $3,158,266, $5,594,040 and $3,336,502, respectively.

        In 2011, in connection with the credit facility, WFEC was granted a net profits interest ("NPI") in substantially all of CEA's oil and gas properties. It was determined that the net book value of oil and gas properties allocable to the NPI was $3,706,000. This amount was charged as a discount to the credit facility and was amortized over the term of the credit facility through its termination. Total amortization for the years ended December 31, 2013, 2012 and 2011 was $894,585, $1,504,760 and $1,306,655, respectively, and is included in interest expense on the accompanying consolidated statements of operations. The NPI was also terminated on July 26, 2013, as further explained in Note C.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

F. CREDIT FACILITIES (Continued)

Deferred Financing Costs

        In connection with obtaining the above credit facilities and subsequent borrowing base redeterminations, the Company and CEA incurred various loan origination fees, legal fees and other costs. These costs are capitalized and amortized over the lives of the respective debt. During 2013, CEA capitalized $4,766,799 of such costs related to the 2013 revolving credit facility and the term loan credit facilities. Total amortization for the years ended December 31, 2013, 2012 and 2011 was $1,604,785, $1,018,874 and $437,023, respectively, and is included in interest expense on the accompanying consolidated statements of operations.

G. STOCKHOLDER AND OTHER LOANS

        At December 31, 2012, the Company had loans from a stockholder and another party as shown below. The loans were fully retired during 2013.

H. PRICE RISK MANAGEMENT

        The Company is exposed to market risks related to the price volatility of natural gas. The Company periodically uses commodity derivative contracts to reduce the effect of price changes on a portion of its future natural gas production, achieve more predictable cash flows in an environment of volatile gas prices and manage its exposure to commodity price risk. These derivative contracts limit the downside risk of adverse price movements but also may limit the Company's ability to benefit from favorable price movements. From time to time, the Company may restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of its existing contracts. All derivative contracts that the Company enters into are at no up-front cost to the Company. Management has assessed the credit risk of these contracts to be minimal and does not require collateral or other security. Similarly, no counterparty has required the Company to provide any form of security guarantee specific to these contracts. The Company does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features.

        Derivative contracts are carried at fair value on the consolidated balance sheets as assets or liabilities. At December 31, 2013 and 2012, the Company's derivative contract assets and liabilities were

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

H. PRICE RISK MANAGEMENT (Continued)

as shown below. The fair value of open contracts is not necessarily indicative of the actual gains or losses that will be realized upon future settlement of the contracts.

        The Company's derivative contracts have not been designated as hedges for accounting purposes; therefore, the changes in the fair value are included in the consolidated statements of operations for the period in which the change occurs. For the years ended December 31, 2013, 2012 and 2011, the Company recognized net gains as follows:

        The Company's credit facilities require it to periodically meet certain minimum levels (based on percentages of projected production volumes) of hedged volumes for a forward period of three years, but not extending past the maturity date of the facilities. The Company was in compliance with this requirement at December 31, 2013. The following table summarizes the Company's open natural gas derivative contracts as of December 31, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

I. RETIREMENT AND INCENTIVE PLANS

Retirement Plan

        The Company has a 401(k) plan that covers all employees. Employees may contribute amounts as allowable by the Internal Revenue Code and plan limitations. The Company is required to make matching contributions equal to 100% of an employee's contributions up to 3% of the employee's compensation plus 50% of the amount of an employee's contributions that exceeds 3% but is less than 5% of the employee's compensation. The Company made matching contributions of $71,991, $62,689 and $27,238 in 2013, 2012 and 2011, respectively.

Incentive Plans

        In 2010, the Company adopted various incentive plans. Certain joint interest owners have agreed to fund their proportionate share of awards.

        The short-term incentive plan consists of quarterly awards that are generally determined as a percentage, varying from 5% to 10%, of each employee's annual compensation. The Company's expense for quarterly awards was $411,845, $396,362 and $333,562 for the years ended December 31, 2013, 2012 and 2011, respectively.

        The long-term incentive plan consists of a project incentive award that is earned upon the earlier of separation from service without cause, death, disability, a change in control of the Company, or the sale of more than 40% of the Company's assets. In all cases, the award is subject to a vesting schedule based on the individual's years of service. The amount of an award for most employees is a multiple of their annual salary. For management level employees, an award will be a percentage, varying from .25% to 3%, of the net profits associated with all of the assets of the Marcellus shale project. Nets profits are defined, in general, as the excess of the value of the assets over the cumulative costs incurred to acquire and develop the assets. The value of the assets may increase or decrease over time due to market and other factors that are not under the Company's control. Therefore, net profits and project incentive awards may increase or decrease over time.

        The Company accrues a liability for future project incentive awards that will be payable to current employees. The amount of the liability is based on each employee's respective vesting, award multiple and salary or project net profits, as applicable, at the time of the accrual. The Company recognizes deferred compensation expense for the increase or decrease in the accrued liability during the reporting period. Deferred compensation expense for project incentive awards was $5,766,137, $(1,211,846) and $7,771,977 for the years ended December 31, 2013, 2013 and 2011, respectively.

        The Company's share of project incentive awards related to separated employees was $1,712,443, $901,679 and $1,649,328 for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in deferred compensation on the consolidated statements of operations. As of December 31, 2013, all separated employees had been paid in full for their project incentive awards

J. COMMITMENTS AND CONTINGENCIES

Buy/Sell Agreement

        The stockholders of the Company have entered into an agreement that stipulates that, prior to a stockholder's sale of his shares to a third party, either the Company or the remaining stockholder has the right to purchase his outstanding shares at a price determined in accordance with the terms of the agreement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

J. COMMITMENTS AND CONTINGENCIES (Continued)

Transportation and Gathering Agreements

        The Company has entered into certain natural gas, crude oil and NGL transportation and gathering agreements with various pipeline carriers. Under certain of these agreements, the Company is obligated to transport minimum daily quantities, or pay for any deficiencies at a specified rate. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. In most cases, the Company's production commitment to these pipelines is expected to exceed minimum daily quantities provided in the agreements. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability.

Performance Bond

        The Company is contingently liable to a surety in respect of a $290,000 bond issued by the surety in favor of the Department of Environmental Protection of Pennsylvania. The bond represents a guarantee of the Company's future performance under various laws, regulations and permits applicable to the Company and its wells. The bond remains in effect until one year after the last of the covered wells is properly plugged.

Litigation

        Two separate complaints have been filed the in Court of Common Pleas of Clarion County, Pennsylvania naming various defendants and naming the Company as an additional defendant. The two complaints have unrelated plaintiffs but the facts and allegations of each case are similar. Each plaintiff is the owner of mineral rights in Clarion County and they executed oil and gas leases with their defendants. In 2008, the defendants sold the leases to Citrus and thereafter, Citrus sold the leases to Northeast Natural Energy LLC ("NNE"). The plaintiffs allege that the defendants' leases expired pursuant to their terms because of inconsistent production and inactivity by the defendants. If the plaintiffs' allegations are upheld, as a consequence the leases did not exist to be sold by the defendants to Citrus and by Citrus to NNE. Therefore, NNE is seeking judgments on Citrus for repayment of the purchase price paid by NNE to Citrus. However, in such event, Citrus would have a similar cause of action against the defendants for repayment of the purchase price paid by Citrus to the defendants. The amount of judgment sought by NNE is $201,875 for the complaint filed in 2012 and $753,600 for the complaint filed in 2013. Based upon the facts, Citrus and its legal counsel believe that the plaintiffs' and NNE's complaints are without merit and that the cases' resolution will not have a material adverse effect on the Company's financial condition or results of operations. Citrus seeks dismissal of both cases and will defend them vigorously. There has been no activity on the 2012 complaint since the first and only deposition was held in May 2013. As of this date there have been no judgments or decisions in either case.

Health Reimbursement Arrangement

        Effective January 1, 2013, the Company adopted a health reimbursement arrangement ("HRA") for full time employees. Actual qualified medical expenses that are not paid by the Company's group health insurance policy are reimbursed to employees up to a yearly maximum amount of $4,000 for single employees and $8,000 for employees with a spouse and/or dependents. Unused amounts do not

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

J. COMMITMENTS AND CONTINGENCIES (Continued)

carry over to subsequent years. Pursuant to this arrangement, the Company reimbursed employees $57,776 during 2013.

Environmental Liabilities

        All of the Company's operations are generally subject to numerous federal, state and local environmental regulations. Such regulations are concerned with, among other things, the disposal of produced brine water and other wastes and the prevention and/or containment of the release of oil or gas into the environment. The amount of future expenditures related to compliance with environmental regulations cannot be determined at this time.

Office Facilities

        The Company leases office space in Colorado, Texas and Pennsylvania. Total rent expense was $285,478, $203,163 and $144,551 for the years ended December 31, 2013, 2012 and 2011, respectively.

        The Company's total future minimum rental commitment is as follows:

        The Company has assigned to another party two leases for office space that it previously occupied. All of the Company's obligations under the two assigned leases were assumed by the assignee for the remaining term of leases. However, in the event of a default by the assignee, the Company remains liable under the terms of the original leases. One of the leases expired February 28, 2013 and the other expires October 31, 2014. Management believes it is unlikely that the Company will be required to make any payments pursuant to this arrangement.

        In 2012, the Company terminated a long-term lease for office space that was vacant. The Company made payments totaling $173,434 in settlement of the liability of $209,420 for future minimum rentals that were required by the lease. This resulted in a gain of $35,986 that is included in other income.

K. RESTATEMENTS

        Although Citrus is a privately held company, management decided to present the 2013 financial statements in accordance with generally accepted accounting principles ("GAAP") for public companies with oil and gas producing activities. In order to present the 2012 and 2011 financial statements on a comparable basis, they have been revised as follows:

•

In all previously issued financial statements, the long-term project incentive plans discussed in Note I were not accounted for in accordance with GAAP. To correct this departure from GAAP, in the accompanying financial statements, the consolidated balance sheet as of December 31, 2012 has been restated to remove deferred project incentive awards from other assets and to add the Company's accrued liability for future payments under the plans, the consolidated statements of operations for the years ended December 31, 2012 and 2011 have been restated to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

K. RESTATEMENTS (Continued)

reflect deferred compensation expense associated with the plans, and retained earnings as of December 31, 2010, was restated by $1,621,935.

•

In previously issued financial statements, depletion of the Company's producing oil and gas properties using the units of production method was computed utilizing estimated proved reserves determined under criteria acceptable for private companies. In the accompanying consolidated statements of operations for the year ended December 31, 2012, depletion expense has been restated to the amount computed using estimated reserves determined in the manner defined by the Securities and Exchange Commission. Depletion expense for the year ended December 31, 2011 has not been restated because the difference was determined to be immaterial.

        In addition, other changes were made to previously issued financial statements as follows:

•

It was determined that oil and gas leases located in Washington state had expired in 2010 without their capitalized costs being charged to operations. Accordingly, oil and properties as of December 31, 2012, and retained earnings as of December 31, 2010, were restated by $425,493.



•

The December 31, 2012 consolidated balance sheet was restated to reflect additional accounts payable for capitalized costs of oil and gas properties.



•

The Company changed its method of accounting for state income taxes from treating such taxes as an expense to treating the payment of the taxes as distributions to the stockholders.

L. SUPPLEMENTAL CASH FLOW INFORMATION

        The Company's supplemental cash flow information for the years ended December 31, 2013, 2012 and 2011, is as follows:

M. SUBSEQUENT EVENTS

        Management has evaluated subsequent events through April 28, 2014, the date on which the financial statements were available to be issued.

*****************************************

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SUPPLEMENTARY INFORMATION

CITRUS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET

DECEMBER 31, 2013

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CITRUS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET (Continued)

DECEMBER 31, 2013

UNAUDITED

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CITRUS ENERGY CORPORATION

CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2013

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Capitalized Costs Relating to Oil and Gas Producing Activities

        The Company's capitalized costs relating to oil and gas producing activities as of December 31, 2013, 2012 and 2011 are as follows:

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

        The Company incurred the following costs for the years ended December 31, 2013, 2012 and 2011:

Oil and Natural Gas Reserves

        Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir 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, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reported reserve estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in financial statement disclosures.

        The following presentation of proved and proved developed reserve quantities provides only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company's control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based.

        The reserve information presented below is based on reports prepared by Miller and Lents, Ltd., an independent oil and gas consulting firm founded in 1948. Preparation of the reports was supervised

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by Carl D. Richard, an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 25 years of relevant experience in the estimation, assessment and evaluation of oil and gas reserves. Miller and Lents, Ltd. is considered a premier firm in the area of reserve estimation.

        The reserves were estimated in accordance with the definitions and guidelines of the Securities and Exchange Commission ("SEC"). The natural gas prices as of December 31, 2013, 2012 and 2011 were based on the respective unweighted 12-month average of the first day of the month Henry Hub Spot Price which equates to $3.670 per MMBtu, $2.757 per MMBtu and $4.118 per MMBtu, respectively. Price adjustments were made based on regional price differentials between benchmark and actual prices and include considerations such as energy content and shrinkage adjustments. The average price used for proved reserves, after appropriate adjustments, was $3.21 per Mcf, $2.72 per Mcf and $4.13 per Mcf, respectively. All prices were held constant in accordance with SEC guidelines.

        The reserves were estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on the evaluation of individual well performance and production decline curve analysis. For proved undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers. Reliable technologies were used to determine areas where proved undeveloped locations are more than one offset away from a producing well. These technologies include seismic data, wire line open hole log data, core data, log cross-sections, performance data, and statistical analysis. In such areas, these data demonstrated consistent, continuous reservoir characteristics. Only production flow tests and historical production data, along with the reliable geologic data mentioned above, were relied upon to estimate proved reserves.

        Proved reserves represent estimated quantities of natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

        Presented below is a summary of the changes in estimated proved reserves of the Company, all of which are natural gas reserves located in the United States, for the years ended December 31, 2013, 2012 and 2011:

        The extensions and discoveries shown above are a result of the Company's active development program on its Ardent II property in the Marcellus shale of northeastern Pennsylvania. In mid 2013, the Company added approximately 44,000 MMcf of proved reserves by acquiring an additional working

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interest in this property. Revisions are the result of changed natural gas prices, historical well performance, additional geological information, and changes to the Company's development plan.

Standardized Measure of Discounted Future Net Cash Flows

        The following standardized measure of discounted future net cash flows ("Standardized Measure") presents only estimates and may not represent realistic assessments of future cash flows and does not purport to reflect realizable values or fair market values of the Company's reserves or represent the current value of the Company.

        The Standardized Measure is computed by applying prices of oil and gas to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the reserves and assuming continuation of existing economic conditions. As specified by the SEC, the prices for oil and gas used in this calculation were the unweighted 12-month average of the first day of the month spot prices, except for volumes subject to fixed price contracts. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Because the Company is taxed under Subchapter S of the Internal Revenue Code, income taxes are not deducted.

        The Standardized Measure at December 31, 2013, 2012 and 2011 is as follows:

Changes in Standardized Measure of Discounted Future Net Cash Flows

        The following is a summary of the changes in the Standardized Measure during the years ended December 31, 2013, 2012 and 2011:

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TLK PARTNERS LLC

BALANCE SHEETS

   

See notes to financial statements.

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TLK PARTNERS LLC

STATEMENTS OF INCOME AND MEMBERS' EQUITY (DEFICIT)

(Unaudited)

   

See notes to financial statements.

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TLK PARTNERS LLC

STATEMENTS OF CASH FLOWS

(Unaudited)

   

See notes to financial statements.

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TLK PARTNERS LLC

NOTES TO FINANCIAL STATEMENTS

March 31, 2014 (Unaudited)

Note 1—Basis of Presentation

        The accompanying unaudited financial information of TLK Partners LLC (the Company) has been prepared in accordance with Financial Accounting Standards Board Accounting Standards Codification 270 Interim Reporting. Management of the Company believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full year.

        Certain amounts and disclosures have been condensed or omitted from these financial statements. Therefore, these financial statements should be read in conjunction with the Company's December 31, 2013 audited financial statements and related notes thereto.

NOTE 2—Income Tax Status

        As a limited liability company, the Company's taxable income or loss is allocated to members in accordance with their respective percentage ownership. Therefore, no provision or liability for income taxes has been included in the accompanying financial statements. The Company is subject to income tax examinations by the federal or state tax authorities for years 2010 (inception) through 2013.

Note 3—Liquidity and Members' Plan

        The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As of March 31, 2014, the Company had cash of $377,227 and a working capital deficiency of $22,979,767 which includes $23,500,000 in bank borrowings payable on December 31, 2014 (see Note 4). The members believe that without debt refinancing, the Company may not have sufficient liquidity to finance the Company's anticipated working capital requirements for at least the next 12 months. While the members believe that the Company will be able to obtain an extension of its bank credit facility on or before its December 31, 2014, maturity date, there can be no assurance that debt refinancing after December 31, 2014, will be available on terms satisfactory to the Company. In the absence of debt refinancing, the members would seek to obtain additional equity financing or sell the Company's natural gas properties to provide sufficient liquidity (see Note 7).

Note 4—Credit Facilities

        Credit facilities consist of the following at March 31, 2014:

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TLK PARTNERS LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

March 31, 2014 (Unaudited)

Note 4—Credit Facilities (Continued)

Note 5—Related Party Transactions

        In the three months ended March 31, 2014 and 2013, the Company made guaranteed payments to members totaling $235,000 and $231,000, respectively, which constituted their salaries for services provided to the Company.

        The Company does not have any employees. The employees supporting the administration and management of the Company are employees of an affiliate. The affiliate provided these services at no charge to the Company in the three months ended March 31, 2014. In the three months ended March 31, 2013, the affiliate charged the Company management fees of $150,000 for administration and management services.

        In the three months ended March 31, 2014 and 2013, the Company had net gains on natural gas trading with an affiliate totaling $251,072 and $241,450, respectively.

Note 6—Concentrations of Credit Risk

        At March 31, 2014, the Company had cash in a financial institution which exceeded federally insured limits. The members believe that credit risk related to this balance is minimal. Substantially all of the Company's natural gas sales are to one purchaser. This purchaser comprised substantially all of accounts receivable natural gas sales at March 31, 2014.

Note 7—Subsequent Event

        On July 6, 2014, the Company entered into a Purchase and Sale Agreement to sell all of its natural gas properties and equipment for $29,633,334 in cash subject to post-closing adjustments. The sale is anticipated to close in August 2014. Pursuant to the Company's Credit Agreement, sales proceeds would be used first to pay off the Company's outstanding bank debt.

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INDEPENDENT AUDITOR'S REPORT

To the Members
TLK Partners LLC

Report on the Financial Statements

        We have audited the accompanying financial statements of TLK Partners LLC which comprise the balance sheets as of December 31, 2013 and 2012, and the related statements of operations and members' deficit, and cash flows for the years then ended and the related notes to the financial statements.

Management's Responsibility for the Financial Statements

        Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

        Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

        We believe that the audit evidence we have obtained is sufficient and appropriate to provide a reasonable basis for our audit opinion.

Opinion

        In our opinion the financial statements referred to above present fairly, in all material respects, the financial position of TLK Partners LLC as of December 31, 2013 and 2012, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ Hogan Taylor LLP

Oklahoma City, Oklahoma
June 25, 2014

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TLK PARTNERS LLC

BALANCE SHEETS

December 31, 2013 and 2012

   

See notes to financial statements

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TLK PARTNERS LLC

STATEMENTS OF OPERATIONS AND MEMBERS' DEFICIT

Years ended December 31, 2013 and 2012

   

See notes to financial statements

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TLK PARTNERS LLC

STATEMENTS OF CASH FLOWS

Years ended December 31, 2013 and 2012

   

See notes to financial statements

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TLK PARTNERS LLC

NOTES TO FINANCIAL STATEMENTS

December 31, 2013 and 2012

Note 1—Summary of Significant Accounting Policies

Nature of operations

        TLK Partners LLC (the Company) was formed in August 2010, as an Oklahoma limited liability company (LLC), and is in the business of exploration and production of natural gas. An LLC limits its members from liability to creditors to the amount of capital contributed to the LLC.

Accounting estimates

        The preparation of the financial statements, in conformity with accounting principles generally accepted in the United States of America, requires management to make estimates and assumptions that affect the reported amounts in the financial statements. Actual results could differ from those estimates.

Natural gas producing activities

        The Company follows the successful efforts method of accounting for natural gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged to expense if and when the well is determined to be nonproductive. Leasehold costs are capitalized when acquired.

        Unproved properties are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms and potential shifts in business strategy employed by the Company. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties' costs, which the Company believes will not be transferred to proved properties over the remaining lives of the leases. Impairment provisions are charged to expense when recognized.

        The Company recognizes revenues as natural gas is produced and sold. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a reservoir cannot be recouped through the production of remaining reserves. At December 31, 2013 and 2012, the Company had no material natural gas imbalances.

        Depreciation, depletion and amortization of the costs of proved properties are computed using the units of production method on a field basis using proved or proved developed reserves, as applicable, as estimated by the Company's independent petroleum engineer.

        The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets' carrying amount. The impairment loss is measured by comparing the fair value of the assets to their carrying amounts. Fair values are based on discounted cash flows as estimated by the Company's independent petroleum engineer.

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TLK PARTNERS LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2013 and 2012

Note 1—Summary of Significant Accounting Policies (Continued)

        The Company's estimate of fair value of its natural gas properties at December 31, 2013 and 2012, was based on the best information available as of those dates, including estimates of forward natural gas prices and costs. The Company's natural gas properties were reviewed for impairment on a field-by-field basis, resulting in no recognition of impairment in 2013 or 2012.

Asset retirement obligations

        The Company owns interests in natural gas properties, which may require expenditures to plug and abandon the wells when the natural gas reserves of the wells are depleted. The fair value of legal obligations to retire and remove long-lived assets is recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, this cost is capitalized by increasing the carrying amount of the related properties and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties and equipment is depreciated over the useful life of the remaining asset.

Income tax status

        As a limited liability company, the Company's taxable income or loss is allocated to members in accordance with their respective percentage ownership. Therefore, no provision or liability for income taxes has been included in the accompanying financial statements. The Company is subject to income tax examinations by the federal or state tax authorities for years 2010 (inception) through 2013.

Subsequent events

        The members have evaluated subsequent events through June 25, 2014, the date the financial statements were available to be issued.

Note 2—Liquidity and Members' Plan

        The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As of December 31, 2013, the Company had cash of $365,996, a working capital deficiency of $23,236,412 which includes $23,500,000 in bank borrowings payable on December 31, 2014 (see Note 4), and a members' deficit of $474,484. In 2013, the Company had net cash provided by operating activities of $2,663,672. The members believe that without debt refinancing, the Company may not have sufficient liquidity to finance the Company's anticipated working capital requirements for at least the next 12 months. While the members believe that the Company will be able to obtain an extension of its bank credit facility on or before its December 31, 2014, maturity date, there can be no assurance that debt refinancing after December 31, 2014, will be available on terms satisfactory to the Company. In the absence of debt refinancing, the members would seek to obtain additional equity financing or sell the Company's natural gas properties to provide sufficient liquidity.

Note 3—Acquisition

        On April 11, 2012, the Company closed an acquisition of certain Marcellus Shale natural gas properties located in Pennsylvania. The Company acquired an average working interest of 5.98% in 20 proved, nonoperated natural gas properties. The purchase price was $19,527,975 and was funded by

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TLK PARTNERS LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2013 and 2012

Note 3—Acquisition (Continued)

utilizing borrowings from the Company's bank credit facility. The purchase price was allocated to the proved natural gas properties based on fair value determined by estimated natural gas reserves.

        Principally all of the Company's natural gas sales and net income included in the accompanying statement of operations for the year ended December 31, 2012, was attributable to this acquisition.

Note 4—Credit Facilities

        Credit facilities consist of the following at December 31:

Note 5—Related Party Transactions

        In 2013 and 2012, the Company made guaranteed payments to members totaling $1,170,000 and $298,000, respectively, which constituted their salaries for services provided to the Company.

        The Company does not have any employees. The employees supporting the administration and management of the Company are employees of an affiliate. The affiliate charged the Company management fees of $600,000 in 2013 for administration and management services. The affiliate provided these services at no charge to the Company in 2012.

        In 2013 and 2012, the Company had net gains on natural gas trading with an affiliate totaling $1,003,154 and $250,682, respectively.

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TLK PARTNERS LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

December 31, 2013 and 2012

Note 6—Concentrations of Credit Risk

        At December 31, 2013 and 2012, the Company had cash in a financial institution which exceeded federally insured limits. The members believe that credit risk related to this balance is minimal. Substantially all of the Company's natural gas sales were to one purchaser in 2013 and 2012. This purchaser comprised substantially all of accounts receivable natural gas sales at December 31, 2013 and 2012.

Note 7—Asset Retirement Obligations

        The following table shows the activity for the years ended December 31, relating to the Company's retirement obligation for plugging liabilities:

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TLK PARTNERS LLC


SUPPLEMENTAL UNAUDITED NATURAL GAS INFORMATION

Natural Gas Reserves

        Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir 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, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reported reserve estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in financial statement disclosures.

        The following presentation of proved and proved developed reserve quantities provides only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company's control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based.

        The reserve information presented below is based on reports prepared by Pinnacle Energy Services, LLC, an independent oil and gas consulting firm founded in 1998. Preparation of the reports was supervised by John Paul Dick, the founder and manager of the firm who is a professionally qualified and licensed Professional Engineer in the States of Oklahoma and Texas with more than 31 years of relevant experience in the estimation, assessment and evaluation of oil and gas reserves.

        The reserves were estimated in accordance with the definitions and guidelines of the Securities and Exchange Commission ("SEC"). The natural gas prices as of December 31, 2013 and 2012 were based on the respective unweighted 12-month average of the first day of the month Henry Hub Spot Price which equates to $3.67 per MMBtu and $2.76 per MMBtu, respectively. Price adjustments were made based on regional price differentials between benchmark and actual prices and include considerations such as energy content and shrinkage adjustments. The average price used for proved reserves, after appropriate adjustments, was $3.42 per Mcf and $2.56 per Mcf, respectively. All prices were held constant in accordance with SEC guidelines.

        The reserves were estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on the evaluation of individual well performance and production decline curve analysis. For proved undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers. Reliable technologies were used to determine areas where proved undeveloped locations are more than one offset away from a producing well. These technologies include seismic data, wire line open hole log data, core data, log cross-sections, performance data, and statistical analysis. In such areas, these data demonstrated consistent, continuous reservoir characteristics. Only

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production flow tests and historical production data, along with the reliable geologic data mentioned above, were relied upon to estimate proved reserves.

        Proved reserves represent estimated quantities of natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

        Presented below is a summary of the changes in estimated proved reserves of the Company, all of which are natural gas reserves located in the United States, for the years ended December 31, 2013 and 2012:

Standardized Measure of Discounted Future Net Cash Flows

        The following standardized measure of discounted future net cash flows ("Standardized Measure") presents only estimates and may not represent realistic assessments of future cash flows and does not purport to reflect realizable values or fair market values of the Company's reserves or represent the current value of the Company.

        The Standardized Measure is computed by applying prices of natural gas to the estimated future production of proved natural gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the reserves and assuming continuation of existing economic conditions. As specified by the SEC, the prices for natural gas used in this calculation were the unweighted 12-month average of the first day of the month spot prices, except for volumes subject to fixed price contracts. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Because the Company is treated as a partnership under the Internal Revenue Code, income taxes are not deducted.

        The Standardized Measure at December 31, 2013 and 2012 is as follows:

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Changes in Standardized Measure of Discounted Future Net Cash Flows

        The following is a summary of the changes in the Standardized Measure during the years ended December 31, 2013 and 2012:

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Citrus Energy Corporation CONSOLIDATED BALANCE SHEETS
Citrus Energy Corporation CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31,
Citrus Energy Corporation CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY FOR THE THREE MONTHS ENDED MARCH 31, 2014
Citrus Energy Corporation CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31,
CITRUS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
INDEPENDENT AUDITORS' REPORT
TO THE STOCKHOLDERS
CITRUS ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS DECEMBER 31,
CITRUS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31,
CITRUS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011
CITRUS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
CITRUS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SUPPLEMENTARY INFORMATION
CITRUS ENERGY CORPORATION CONSOLIDATED BALANCE SHEET DECEMBER 31, 2013
CITRUS ENERGY CORPORATION CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2013
TLK PARTNERS LLC BALANCE SHEETS
TLK PARTNERS LLC STATEMENTS OF INCOME AND MEMBERS' EQUITY (DEFICIT) (Unaudited)
TLK PARTNERS LLC STATEMENTS OF CASH FLOWS (Unaudited)
TLK PARTNERS LLC NOTES TO FINANCIAL STATEMENTS March 31, 2014 (Unaudited)
INDEPENDENT AUDITOR'S REPORT
TLK PARTNERS LLC BALANCE SHEETS December 31, 2013 and 2012
TLK PARTNERS LLC STATEMENTS OF OPERATIONS AND MEMBERS' DEFICIT Years ended December 31, 2013 and 2012
TLK PARTNERS LLC STATEMENTS OF CASH FLOWS Years ended December 31, 2013 and 2012
TLK PARTNERS LLC NOTES TO FINANCIAL STATEMENTS December 31, 2013 and 2012
TLK PARTNERS LLC SUPPLEMENTAL UNAUDITED NATURAL GAS INFORMATION