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HDY > SEC Filings for HDY > Form 10-K on 11-Sep-2013All Recent SEC Filings

Show all filings for HYPERDYNAMICS CORP

Form 10-K for HYPERDYNAMICS CORP


11-Sep-2013

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Overview

Our corporate mission is to provide energy for the future by exploring for, developing new, and re-establishing pre-existing sources of energy. Our primary focus is the advancement of exploration work in Guinea. We also plan to continue to evaluate and consider other global oil and gas opportunities. We have no source of operating revenue, and there is no assurance when we will, if ever. We have no operating cash flows, and we will require substantial additional funds, through additional participants, securities offerings, or through other means, to fulfill our business plans.

Our operating plan within the next 12 months includes the following:


Initiate with Tullow and Dana a new drilling program in the deep water and commence drilling of an exploration well in the first calendar quarter of 2014.


Continue to evaluate and consider other global oil and gas opportunities.

Analysis of changes in financial position

Our current assets increased by $556,000 from $42,723,000 on June 30, 2012 to $43,279,000 on June 30, 2013. The increase in current assets is due to the $23.7 million in net cash proceeds received on the sale of a 40% interest in the Concession to Tullow. This was offset by cash used for general and administrative expenditures as well as capital expenditures.


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Our long-term assets decreased $18,984,000, from $60,073,000 on June 30, 2012, to $41,089,000 on June 30, 2013. This decrease was primarily due the reduction to our full cost pool upon the receipt of $23.7 million in net proceeds received on the sale of a 40% interest in the Concession to Tullow. This was offset by $5.4 million in capital expenditures associated with the processing of our most recent 4,000 square kilometer 3D seismic survey.

Our current liabilities decreased $4,002,000, from $26,604,000 on June 30, 2012 to $22,602,000 on June 30, 2013. The decrease in current liabilities can be attributed in part to a decrease in accrued employee bonus expense resulting from the timing of bonus payments.

Our long-term liabilities decreased from $125,000 at June 30, 2012, to $92,000 at June 30, 2013, due to the amortization of deferred rent during the year.

Results of Operations

Based on the factors discussed below, the net loss attributable to common shareholders for the year ended June 30, 2013, decreased $130,852,000, to a net loss of $18,461,000, or $0.88 per share in the 2013 period from a net loss of $149,313,000, or $7.44 per share in the 2012 period (in each case, after giving effect to the 1-for-8 Reverse Stock Split effected July 1, 2013). The net loss attributable to common shareholders for the year ended June 30, 2012, increased $138,075,000, to a net loss of $149,313,000, or $7.44 per share in the 2012 period from a net loss of $11,238,000, or $0.72 per share in the 2011 period (in each case, after giving effect to the 1-for-8 Reverse Stock Split effected July 1, 2013).

Reportable segments

We have one reportable segment: our international operations in Guinea conducted through our subsidiary SCS. SCS is engaged in oil and gas exploration activities pertaining to offshore Republic of Guinea.

Comparison for Fiscal Year 2013 and 2012

Revenues. There were no revenues for the years ended June 30, 2013 and 2012.

Depreciation. Depreciation decreased 24%, or $197,000, from the fiscal 2012 period to the fiscal 2013 period. Depreciation expense was $630,000 and $827,000 in the years ended June 30, 2013 and 2012, respectively. The decrease is primarily attributed to assets used in the prior period relating to drilling operations being fully depreciated or sold in the current period.

General, Administrative and Other Operating Expenses. Our general, administrative and other operating expenses were $17,474,000 and $22,062,000 for the years ended June 30, 2013 and 2012, respectively. This represents a decrease of 20.8%, or $4,588,000 from the fiscal 2012 period to the fiscal 2013 period. Of this decrease, $2,045,000 is attributable to a decrease in non-cash stock compensation from $5,025,000 in the 2012 to $2,980,000 in the 2013 (including $365,000 in non-cash expense associated with an award of common shares associated with a severance agreement in the current year).

The remaining $2,543,000 decrease in expense was primarily attributable to a decrease in costs associated with prospective oil and gas investment opportunities of approximately $3,747,000. Additionally, there was a decrease in travel expenses of approximately $407,000 primarily as a result of the closure of our offices in Guinea and London. This was offset by an increase in employee related costs of $577,000, which is the result of a $1,660,000 increase in severance costs associated with staff reductions offset by a $1,083,000 decrease in recurring payroll expense as a result of the staff reductions. Additionally, there were increases in legal and accounting fees of approximately $569,000, and a decrease in foreign currency transaction gains from current operations in the current period of approximately $568,000. Our foreign currency transaction gains are the result of a large balance in


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accounts payable denominated in foreign currency, primarily associated with our drilling contract with AGR, for which payment has been frozen pending the resolution of our legal dispute with AGR.

Amortization and Write off of Costs. We fully amortized our proved oil and gas properties of $116,312,000 and wrote off a prospective investment deposit of $10,000,000 during the year ended June 30, 2012. We amortized an additional $441,000 of proved oil and gas properties during the year ended June 30, 2013. These are additional costs recognized during the year ended June 30, 2013 associated with the non-commercial Sabu-1 well. As required by the Full-Cost Accounting rules, we evaluated and moved these costs to proved properties and then fully amortized them through our Full-Cost Ceiling Test.

Other income (expense). Other income (expense) totaled $84,000 and $(112,000) for the years ended June 30, 2013 and 2012, respectively. The increase in other income is primarily the result of the reversal to net income of other than temporary impairment of available-for-sale securities of $472,000 during fiscal 2012 while there was no such reversal in the current period. This was offset by a decrease in interest income from 2012 to 2013.

Loss from Continuing Operations. Primarily as a result of the full amortization of proved oil and gas properties and the write off of the prospective investment deposit discussed above, which together total $126,312,000 in fiscal 2012, and the decrease in selling, general and administrative expenses of $4,588,000 our loss from continuing operations decreased by $130,852,000, from $149,313,000 in the year ended June 30, 2012 to $18,461,000 for the year ended June 30, 2013.

Comparison for Fiscal Year 2012 and 2011

Revenues. There were no revenues for the years ended June 30, 2012 and 2011.

Depreciation. Depreciation increased 134%, or $474,000 due to additional depreciation associated with assets placed in service in 2012 which relate primarily to assets put in place to drill our first exploratory well. Depreciation expense was $827,000 and $353,000 in the years ended June 30, 2012 and 2011, respectively.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $22,062,000 and $10,516,000 for the years ended June 30, 2012 and 2011, respectively. This represents an increase of 110%, or $11,546,000 from the fiscal 2011 period to the fiscal 2012 period. The increase in expense was primarily attributable to a $6,716,000 increase in employee-related costs, of which approximately $2,849,000 was non-cash stock-based compensation related to options granted to employees and others. This was driven by an increase in our full time staff from 28 employees as of July 1, 2010 to 53 employees as of June 30, 2012. The staffing increase primarily related to personnel required for our activities in Guinea and our support staff. Additionally, we incurred approximately $3,747,000 in costs with respect to several prospective oil and gas investment opportunities in the current fiscal period.

Amortization and Write off of Costs. We fully amortized our proved oil and gas properties of $116,312,000. As a result of the non-commercial Sabu-1 well drilling outcome, as required by Full-Cost Accounting rules, we evaluated and moved to proved properties $116,312,000 of costs which were then fully amortized though our Full-Cost Ceiling Test. Additionally we have written off a prospective investment deposit of $10,000,000.

Other income (expense). Other income (expense) totaled $(112,000) and $(369,000) for the years ended June 30, 2012 and 2011, respectively. The decrease is primarily the result of a loss on the warrant derivative liability in the prior fiscal period. In the fiscal 2011 period, we recognized a non-cash loss on the warrant derivative liability of $771,000. No such gain or loss was incurred on the warrant derivative liability in fiscal 2012 as the remaining warrants underlying the derivative were exercised


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during the second quarter of fiscal 2011. However, we recognized an other than temporary impairment of available-for-sale securities of $472,000 during fiscal 2012.

Loss from Continuing Operations. Primarily as a result of the full amortization of proved oil and gas properties and the write off of the prospective investment deposit discussed above, which together total $126,312,000, and the increase in selling, general and administrative expenses of $11,546,000 our loss from continuing operations increased by $138,075,000, from $11,238,000 in the year ended June 30, 2011 to $149,313,000 for the year ended June 30, 2012.

Liquidity and Capital Resources

Capital Resource Considerations

On December 31, 2012, our wholly owned subsidiary, SCS, closed a sale to Tullow Guinea Ltd ("Tullow"), a subsidiary of Tullow Oil plc, of a 40% gross interest in the Concession. As consideration, SCS received $27 million from Tullow as reimbursement of past costs of SCS in the Concession, and as additional consideration, Tullow agreed to: (i) pay SCS's participating interest share of future costs associated with the drilling of an exploration well in at least 2,000 meters of water in the deep water fan area of the Concession, up to a gross expenditure cap of $100 million, and (ii) pay SCS's share of costs associated with an appraisal well of the initial exploration well, if drilled, subject to a gross expenditure cap on the appraisal well of $100 million. Tullow is obligated to pay its 40% participating interest share of costs associated with the Concession as of November 20, 2012, the date of execution of the purchase and sale agreement. Tullow will begin to pay SCS's costs attributable to the Concession at the earlier of (i) the commencement of the next exploration period, September 21, 2013, or (ii) should a decision be made to begin spending on an exploration well prior to committing to the next exploration period, the date of such spending. Tullow will continue to pay SCS's costs, subject to the gross expenditure cap of $100 million, until 90 days following the date on which the rig contracted to drill the exploration well moves off the well location. As part of our agreement, Tullow will use reasonable endeavors to provide for the commencement of drilling of the exploration well not later than April 1, 2014.

The December 2012 sale to Tullow improved our cash position and liquidity, and we have adequate funds to conduct our current operations. However, our ability to drill additional wells may depend on obtaining additional resources through sales of additional interests in the Concession, equity or debt financings, or through other means. If we farm-out additional interests in the Concession, our percentage will decrease. Although we have been successful in raising capital and in entering into key participation arrangements with Dana and Tullow, we have no firm commitments for additional capital resources. The terms of any such arrangements, if made, are unknown, and may not be advantageous.

Liquidity

On June 30, 2013, we had $26.5 million in cash, $15.4 million in available-for-sale securities and $19.2 million in restricted cash, which is held in escrow in connection with our drilling contract with AGR. We had $22.7 million in liabilities, which are comprised of current liabilities of $22.6 million, which includes $20.2 million of liabilities currently pending resolution of our dispute with AGR, and noncurrent liabilities of $0.1 million. We plan to use our existing cash to fund our general corporate needs 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.

We have filed suit against AGR following unsuccessful negotiations to address the cost overruns associated with the Sabu-1 well. Payment of the remaining drilling costs is pending resolution of this dispute. AGR filed a countersuit on October 1, 2012 in which AGR has made claims 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 dispute and have excluded from cost incurred to date. Additionally, AGR holds $8.8 million on a gross


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basis of excess materials acquired during the drilling of the Sabu-1 well. We dispute AGR's entitlement to these assets. Resolution of this dispute may result in the recovery of a portion of the costs incurred to date; however, it is possible that the resolution of this dispute may result in additional liability associated with disputed costs.

We have satisfied all requirements of the current exploration period, which runs until September 2013 under the Concession. The Consortium sent notice to the Government of Guinea of our intention to renew the second exploration period to September 2016 and the coordinates of the area to be relinquished as required under the PSC. The second exploration period may be extended for one additional year beyond 2016 to allow the completion of a well in process and for two additional years to allow the completion of the appraisal of any discovery made. Additionally, to satisfy the September 2013-2016 work requirement, an additional exploration well is required to be drilled, which is to be commenced by the end of September 2016, to a minimum depth of 2,500 meters below seabed. We plan to commence the drilling of a deepwater exploration well during the first quarter of calendar 2014, which would satisfy the requirement to drill in the second exploration period. Tullow has agreed to pay SCS's participating interest share of future costs associated with the drilling of this well, up to a gross expenditure cap of $100 million. Additionally, Tullow has agreed to pay SCS's participating interest share of future costs associated with the drilling of an appraisal of the initial exploration well, if drilled, up to a gross expenditure cap of $100 million. We are responsible for our share of any costs exceeding the gross expenditure cap of $100 million on either well.

We have made adjustments to our overhead costs in connection with the transfer of operatorship to Tullow on April 1, 2013. Overhead adjustments during the year ended June 30, 2013 included Houston office staff reductions and the closure of our offices in London and Guinea.

We are currently involved in various legal proceedings. We are unable to predict the outcome of such matters; however, an adverse development could have an impact on liquidity.

Net cash used in operating activities for the year ended June 30, 2013 was $15,617,000 compared to $12,438,000 for the year ended June 30, 2012. The increase in cash used in operating activities is primarily attributable to changes in working capital during the period. Cash provided by investing activities for the year ended June 30, 2013 was $4,565,000 compared to cash used in investing activities of $59,135,000 in the year ended June 30, 2012. This decrease in cash used was primarily attributable to a decrease in capital expenditures from 2012, during which we drilled a well, to 2013. Additionally, in the current period we received $23.7 million in net proceeds from the sale of an interest in our oil and gas properties. This was offset by the purchase of $15.5 million in available-for-sale securities in the current year compared to the prior period in which proceeds from the sale of available-for-sale securities were approximately $53.8 million. There was net cash provided by financing activities for the year ended June 30, 2013 of $372,000 compared to $28,832,000 during the year ended June 30, 2012. We received approximately $28,162,000 in proceeds from the issuance of stock during fiscal 2012, whereas no cash was received for the issuance of stock in the current year.

Contractual Commitments and Obligations

Our subsidiary, SCS, has $350,000 remaining of a contingent note payable due to the former owners of SCS Corporation's assets. It is payable in our common stock and it is payable only if SCS has net income in any given quarter. If SCS experiences net income in a quarter, 25% of the income will be paid against the note, until the contingency is satisfied.


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           Disclosure of Contractual Obligations as of June 30, 2013

                                                Payments due by period ($thousands)
                                           Less than                                       More than
Contractual Obligations         Total        1 year       1 - 3 years      3 - 5 years      5 years
Installment Obligations        $     72      $     72      $         -         $      -       $     -
Operating Lease Obligations         704           420              285                -             -

Total(1)                       $    776      $    492      $       285         $      -       $     -


(1)
We are subject to certain commitments under the PSC as discussed in Item 1 above.

CRITICAL ACCOUNTING POLICIES

Our Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States, which require us to make estimates and assumptions that affect the reported amounts of assets and liabilities and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates, including those estimates that may have a significant effect on our financial condition and results of operations. Our significant accounting policies are disclosed in Note 1 to our Consolidated Financial Statements. The following discussion of critical accounting policies addresses those policies that are both important to the portrayal of our financial condition and results of operations and require significant judgment and estimates. We base our estimates and judgment on historical experience and on various other factors that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

Oil and Gas Properties

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 proved 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 cost 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 is 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 a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. In accordance with SEC release 33-8995, 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, are used in deriving future net revenues discounted at 10%, net of tax. The application of the full-cost method of accounting for oil and gas properties generally results in higher capitalized costs and higher depreciation, depletion and amortization rates compared to the successful efforts method of accounting for oil and gas properties.

Costs Excluded

Costs associated with unevaluated properties are excluded from the full-cost pool until we have made a determination as to the existence of proved reserves. We review our unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full-cost pool and thereby subject to amortization.


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We assess all items classified as unevaluated 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; 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 unevaluated properties on a country-by-country basis. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full-cost pool and are then subject to amortization. However, if proved reserves have not yet been established in a full-cost pool, these costs are charged against earnings. For international operations where a reserve base has not yet been established, an impairment requiring a charge to earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or other information. At June, 30, 2013, we had $20.2 million of capitalized costs associated with our Guinea operations, which is net of $116.8 million in amortization as a result of reclassifying costs incurred on previously unevaluated properties to proved properties.

Environmental Obligations and Other Contingencies

Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental remediation, litigation and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. Estimates of environmental liabilities are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change our estimate of environmental remediation costs, such as changes in laws and regulations, or changes in their interpretation or administration, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental or other contingent matters and actual costs may vary significantly from our estimates.

Fair Value of our debt and equity transactions

Many of our various debt and equity transactions require us to determine the fair value of a debt or equity instrument in order to properly record the transaction in our financial statements. Fair value is generally determined by applying widely acceptable valuation models, (e.g., the Black Scholes and binomial lattice valuation models) using the trading price of the underlying instrument or by comparison to instruments with comparable maturities and terms.

Share-Based Compensation

We follow ASC 718 which 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). ASC 718 also requires measurement of 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 the provisions of ASC 505-50, "Equity-Based Payments to Non-Employees."


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