1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Nature of business

Hyperdynamics Corporation (“Hyperdynamics,” the “Company,” “we,” “us,” and “our”) is a Delaware corporation formed in March 1996. Hyperdynamics has two wholly-owned subsidiaries, SCS Corporation Ltd (SCS), a Cayman corporation, and HYD Resources Corporation (HYD), a Texas corporation. Through SCS and its wholly-owned subsidiary, SCS Guinea SARL (SCSG), which is a Guinea limited liability company formed under the laws of the Republic of Guinea (“Guinea”) located in Conakry, Guinea, Hyperdynamics focuses on oil and gas exploration offshore the coast of West Africa. Our exploration efforts are pursuant to a Hydrocarbon Production Sharing Contract, as amended (the “PSC”). We refer to the rights granted under the PSC as the “Concession.” We began operations in oil and gas exploration, seismic data acquisition, processing, and interpretation in late fiscal 2002.

As used herein, references to “Hyperdynamics,” “Company,” “we,” “us,” and “our” refer to Hyperdynamics Corporation and our subsidiaries, including SCS Corporation Ltd (“SCS”). The rights in the Concession offshore Guinea are held by SCS.

Status of our Business

We have no source of operating revenue and there is no assurance when we will, if ever. On June 30, 2014, we had $35.3 million in cash, and $5.7 million in liabilities, all of which are current liabilities. We plan to use our existing cash to fund our general corporate needs, our legal and other professional fees and our expenditures associated with the Concession, including our share of future capital expenditures that are not paid by Tullow on our behalf. We have no other material commitments; however, we have incurred significant legal expenses in the year ended June 30, 2014, and it is likely that we will continue to incur significant expenses in the year ending June 30, 2015.

On December 31, 2012, we closed a sale to Tullow Guinea Ltd (“Tullow”), a subsidiary of Tullow Oil plc, of a 40% gross interest in the Concession. We now hold a 37% participating interest, with Dana Petroleum, PLC (“Dana”), which is a subsidiary of the Korean National Oil Corporation, holding the remaining 23% interest in the Concession. We refer to Tullow, Dana and us in the Concession as the “Consortium”.

We have drilled one exploratory well, the Sabu-1 well, which reached the planned total depth of 3,600 meters below the surface in February 2012. We determined the well to be non-commercial. As a result, we evaluated the costs associated with the well, subjected them to the Full-Cost Ceiling Test, resulting in a Full-Cost Ceiling Test write-down. See additional discussion in Note 3. As described in Note 9, we had filed suit for monetary damages against AGR, the manager of the Sabu-1 well, following unsuccessful negotiations to address mismanagement that led to significant well cost overruns. AGR filed a countersuit for additional cost of $9.5 million on a gross basis or $7.3 million based on the 77% interest we then held, which we disputed and excluded from our cost incurred to date. On May 16, 2014 we reached a settlement of this litigation that resulted in the release to us of $17.7 million of the $19.2 million in long term restricted cash then held in escrow, and the release to AGR of $6.8 million in excess drilling equipment as part of the settlement. Our claims and the counterclaims of AGR were released, and the litigation has been terminated. The net proceeds to us were approximately $15.8 million, after reconciliation of the joint interest account with Dana Petroleum, the other working interest holder during the drilling

Since September 2013, we have received subpoenas from the United States Department of Justice (“DOJ”) and the United States Securities and Exchange Commission (“SEC”) requesting that we produce documents relating to our Concession in Guinea. See additional discussion in Note 9. We are unable to predict the outcome or future cost associated with legal proceedings and the investigations being conducted by the DOJ and SEC; however, we incurred approximately $7.5 million in legal and other professional fees related to the investigations in the year ended June 30, 2014, and it is likely that we will incur significant expenses for legal and associated costs in the year ending June 30, 2015.

Pursuant to the Share Purchase Agreement (“SPA”) between Tullow and us, Tullow agreed to pay all of our participating interest share of expenditures associated with joint operations in the Concession up to a gross expenditure cap of $100 million incurred during the carry period that began on September 21, 2013. From September 2013 until June 30, 2014, costs applied against the $100 million carry were $14.1 million. The timing of the well and the cost estimate are subject to change. We will be responsible for our 37% interest share of the cost in excess of the remaining gross carry amount. Additionally, Tullow agreed to pay our participating interest share of future costs for the drilling of an appraisal of the initial exploration well, if drilled, up to a gross expenditure cap of $100 million.

The Consortium planned to drill the exploration well in the ultra-deepwater portion of the Concession in the first half of calendar 2014. On March 11, 2014 Tullow unilaterally asserted its claim that there had been a Force Majeure event under the PSC with the Government of Guinea, the Joint Operating Agreement (“JOA”) between Dana, Tullow and us and the SPA. Tullow stated in its notice that the decisions by the DOJ and the SEC to open investigations into our activities in obtaining and retaining the Concession rights constituted a Force Majeure event under the terms of the PSC, JOA and SPA. Tullow unilaterally lifted its declaration of Force Majeure effective May 3, 2014. Diligent efforts are being made to satisfy the conditions to resuming petroleum operations which include clarification that the investigations of Hyperdynamics will not adversely affect operations under the PSC. We cannot predict the timing or outcome of these efforts.

Our costs related to the items referred to above and any additional expenses, or any negative outcomes, could adversely affect our liquidity and financial condition and results of operations. We also will be responsible for our participating interest share of costs in excess of $100 million gross costs associated with joint operations expenditures, including operator overhead and the ultra-deepwater exploration well when drilled, and such excess expenditures could exacerbate our liquidity. Absent cash inflows, we could exhaust our current available liquidity within the next twelve months. The timing and amount of our cash outflows are dependent on a number of factors including: legal and other professional fees related to the FCPA investigations, a negative outcome related to any of our legal proceedings and investigations, well costs exceeding our carry, or if we have unfavorable well results. As a result, absent cash inflows, there is substantial doubt as to whether we will have adequate capital resources to meet our current obligations as they become due and therefore be able to continue as a going concern. Our ability to meet our current obligations as they become due over the next twelve-months, and to be able to continue exploration, will depend on obtaining additional resources through sales of additional interests in the Concession, equity or debt financings, or through other means, although no assurance can be given that any of these actions can be completed.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Hyperdynamics and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States and the rules of the Securities and Exchange Commission (SEC).

Use of Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses at the balance sheet date and for the period then ended. Actual results could differ from these estimates.

Cash and cash equivalents

Cash equivalents are highly liquid investments with an original maturity of three months or less. For the years presented, we maintained all of our cash in bank deposit accounts which, at times, exceed the federally insured limits.

Restricted cash

Included in restricted cash as of June 30, 2013 is $19.2 million held in escrow which related to our drilling contract with AGR. Under the terms of the drilling contract, we funded the escrow account for the sole purpose of funding our drilling project as overseen by AGR. As of June 30, 2014, our restricted cash balance is zero as a result of the legal settlement with AGR.

Joint interest receivable and allowance for doubtful accounts

We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. Accounts receivable are written down to reflect management’s best estimate of realizability based upon known specific analysis, historical experience, and other currently available evidence of the net collectible amount. There is no allowance for doubtful accounts as of June 30, 2014 or 2013. At June 30, 2014, all of our accounts receivable balance was related to joint interest billings to Tullow and Dana Petroleum (E&P) Limited (“Dana”), who own 40% and 23% participating interests, respectively in the Concession.

Securities classified as available-for-sale

Management determines the appropriate classification of debt securities at the time of purchase and reevaluates such designation as of each balance sheet date. Marketable equity securities and debt securities not classified as held-to maturity are classified as available-for-sale. Available-for-sale securities are carried at fair value, with unrealized gains and losses, net of tax, reported in other comprehensive income. Realized gains and losses, and declines in value deemed to be other-than-temporary, are included in earnings.

The cost of securities sold is based on the specific identification method. Interest and dividends on securities classified as available-for-sale are included in earnings.

Oil and Gas Properties

Full-Cost Method

We account for oil and natural gas producing activities using the full-cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Accordingly, all costs incurred in the acquisition, exploration, and development of oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. All selling, general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of capitalized costs to proved reserves would significantly change, or to the extent that the sale proceeds exceed our capitalized costs. Depletion of evaluated oil and natural gas properties would be computed on the units of production method based on proved reserves. The net capitalized costs of proved oil and natural gas properties are subject to quarterly impairment tests.

Costs Excluded from Amortization

Costs associated with unproved properties are excluded from amortization until it is determined whether proved reserves can be assigned to the properties. We review our unproved properties at the end of each quarter to determine whether the costs incurred should be transferred to the amortization base.

We assess unproved property on a quarterly basis for possible impairment or reduction in value. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term under our concession; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. We assess our unproved properties on a country-by-country basis. During any period in which these factors indicate an impairment, the adjustment is recorded through earnings of the period.

Full-Cost Ceiling Test

At the end of each quarterly reporting period, the capitalized costs less accumulated amortization and deferred income taxes shall not exceed an amount equal to the sum of the following items: (i) the present value of estimated future net revenues of oil and gas properties (including future development and abandonment costs of wells to be drilled) using prices based on the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements, discounted at 10%, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less related income tax effects (“Full-Cost Ceiling Test”).

The calculation of the Full-Cost Ceiling Test is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. We have no proved reserves.

We recognized no Full-Cost Ceiling test write-downs in the year ended June 30, 2014. During the years ended June 30, 2013 and 2012 we had Full-Cost Ceiling Test write-downs of $0.4 million and $116.3 million, respectively.

Property and Equipment, other than Oil and Gas

Property and equipment are stated on the basis of historical cost less accumulated depreciation. Depreciation is provided using the straight-line method over the estimated useful lives of the assets, generally three to five years.

Provision for Impairments of Long-lived Assets

Long-lived assets are reviewed for impairment annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment loss recognized is the excess of the carrying amount over the fair value of the asset. Any impairment charge is recorded through current period earnings. We recognized no impairment charges in the years ended June 30, 2014, 2013 or 2012, respectively.

Income Taxes

We account for income taxes in accordance with FASB Accounting Standards Codification (“ASC”) 740, “Income Taxes,” which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the tax and financial reporting basis of assets and liabilities and for loss and credit carryforwards. Valuation allowances are provided when recovery of deferred tax assets is not considered likely.

Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in our tax returns that do not meet these recognition and measurement standards. For the year ended June, 30, 2014 the Company has unrecognized tax benefits totaling $5.5 million.

Our policy is to recognize potential accrued interest and penalties related to unrecognized tax benefits within income tax expense. For the years ended June 30, 2014, 2013 and 2012, we did not recognize any interest or penalties in our consolidated statement of operations, nor did we have any interest or penalties accrued on our consolidated balance sheet at June 30, 2014 and 2013 relating to unrecognized benefits.

The tax years 2009-2013 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

Stock-Based Compensation

ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award. We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.”

Earnings Per Share

Basic loss per common share has been computed by dividing net loss by the weighted average number of shares of common stock outstanding during each period. In a period of earnings, diluted earnings per common share are calculated by dividing net income available to common shareholders by weighted-average common shares outstanding during the period plus weighted-average dilutive potential common shares. Diluted earnings per share calculations assume, as of the beginning of the period, exercise of stock options and warrants using the treasury stock method.

All potential dilutive securities, including potentially dilutive options, warrants and convertible securities, if any, were excluded from the computation of dilutive net loss per common share for the years ended June 30, 2014, 2013 and 2012, respectively, as their effects are antidilutive due to our net loss for those periods.

Stock options to purchase approximately 1.4 million common shares at an average exercise price of $8.76 and warrants to purchase approximately 0.03 million shares of common stock at an average exercise price of $11.69 were outstanding at June 30, 2014. Using the treasury stock method, had we had net income, approximately 1,412 common shares attributable to our outstanding stock options would have been included in the fully diluted earnings per share for the year ended June 30, 2014. There would have been no dilution attributable to our outstanding warrants to purchase common shares. Had we had net income, approximately 21,030 common shares attributable to our outstanding unvested restricted stock awards would have been included in the fully diluted earnings per share for the year ended June 30, 2014.

Stock options to purchase approximately 1.4 million common shares at an average exercise price of $13.12 and warrants to purchase approximately 0.4 million shares of common stock at an average exercise price of $10.40 were outstanding at June 30, 2013. Using the treasury stock method, had we had net income, approximately 0.04 million common shares attributable to our outstanding stock options would have been included in the fully diluted earnings per share calculation for the year ended June 30, 2013. There would have been no dilution attributable to our outstanding warrants to purchase common shares.

Stock options to purchase approximately 1.6 million common shares at an average exercise price of $16.72 and warrants to purchase approximately 1.7 million shares of common stock at an average exercise price of $23.52 were outstanding at June 30, 2012. Using the treasury stock method, had we had net income, approximately 0.4 million common shares attributable to our outstanding stock options and 0.2 million common shares attributable to our outstanding warrants to purchase common shares would have been included in the fully diluted earnings per share calculation for the year ended June 30, 2012.

Contingencies

We are subject to legal proceedings, claims and liabilities. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred. See Note 9 for more information on legal proceedings.

Accumulated Other Comprehensive Income (Loss), net of tax

We follow the provisions of ASC 220, “Comprehensive Income”, which establishes standards for reporting comprehensive income. In addition to net income (loss), comprehensive income (loss) includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. At June 30, 2014, we had a balance in “Accumulated other comprehensive loss, net of income tax” on the consolidated balance sheet of zero. The components of accumulated other comprehensive loss and related tax effects were as follows (in thousands):

	Gross Value			Tax Effect		Net of Tax Value
Accumulated other comprehensive loss at June 30, 2012	$	—		$	—	$	—
Change in fair value of available-for-sale securities	94			—		94
Accumulated other comprehensive loss at June 30, 2013	$	94		$	—	$	94
Change in fair value of available-for-sale securities	(25		)	—		(25		)
Reclassification adjustment for realized losses included in net loss	(69		)	—		(69		)
Accumulated other comprehensive loss at June 30, 2014	$	—		$	—	$	—

There is no tax effect of the unrealized gain (loss) in other comprehensive income given our full valuation allowance against deferred tax assets. Total comprehensive loss was $17.0 million, $18.6 million and $149.0 million in fiscal year 2014, 2013 and 2012, respectively.

Financial instruments

The accounting standards (ASC 820, “Fair Value Measurements and Disclosures”) regarding fair value of financial instruments and related fair value measurements define fair value, establish a three-level valuation hierarchy for disclosures of fair value measurement, and enhance disclosure requirements for fair value measures.

The three levels are defined as follows:

· Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

· Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

· Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The carrying values of cash and cash equivalents, accounts receivable — joint interest and accounts payable approximate fair value. Available-for-sale securities, which consist entirely of Corporate Debt securities, were valued at the closing price reported in the active market in which the security was traded. As of June 30, 2014, there were no remaining investments on hand.

The following table sets forth by level within the fair value hierarchy, our financial assets and liabilities (in thousands) that were accounted for at fair value on a recurring basis as of June 30, 2013:

	Carrying Value at		Fair Value Measurement at June 30, 2013
	June 30, 2013		Level 1		Level 2		Level 3
Assets:
Corporate debt securities	$	15,383	$	15,383	$	—	$	—

Foreign currency gains and losses from current operations

In accordance with ASC Topic 830, Foreign Currency Matters, the functional currency of our international subsidiaries is the U.S. Dollar. Gains and losses from foreign currency transactions arising from operating assets and liabilities are included in general, administrative and other operating expense, have not been significant. Net foreign currency transaction gains (losses) were ($0.6) million, $0.1 million and $0.6 million for the years ended June 30, 2014, 2013 and 2012, respectively.

Recently issued or adopted accounting pronouncements

In July 2013, the FASB issued ASU 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward exists, which requires that an entity present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. ASU 2013-11 eliminates diversity in practice for presentation of an unrecognized tax benefits when such a carryforward is available to reduce the taxable income or tax payable that would result from the disallowance of a tax position. This accounting guidance will be effective for our first quarter in fiscal 2015. We do not expect ASU 2013-11 to have any impact on our financial position or results of operations.

Subsequent Events

The Company evaluated all subsequent events from June 30, 2014 through the date of issuance of these financial statements.