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­­UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

☒	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934: For the quarterly period ended January 31, 2015

or

☐	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934: For the transition period from _______ to _________

Commission file number: 000-53313

(Exact name of registrant as specified in its charter)

800 Gessner, Suite 375

(Address of principal executive offices, including zip code)

(Registrant’s principal executive office telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x    No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  x     No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o   No x

As of March 17, 2015, 21,266,794 shares of common stock, $0.001 par value, were outstanding.

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Table of Contents

Part I. Financial Information

 

 

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Part I. Financial Information

 

 

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HYDROCARB ENERGY CORP.

 Consolidated Balance Sheets

(Unaudited)

The accompanying notes are an integral part of these unaudited consolidated financial statements

 

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HYDROCARB ENERGY CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

(Unaudited)

The accompanying notes are an integral part of these unaudited consolidated financial statements

 

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HYDROCARB ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

                                             

The accompanying notes are an integral part of these unaudited consolidated financial statements

 

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HYDROCARB ENERGY CORP.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Description of Business and Summary of Significant Accounting Policies

Description of business and basis of presentation

The unaudited consolidated financial statements of Hydrocarb Energy Corp. (“Hydrocarb”, “HEC”, the “Company”, “we”, “us”, “our”) have been prepared in accordance with accounting principles generally accepted in the United States and the rules of the Securities and Exchange Commission (“SEC”), and should be read in conjunction with the audited financial statements and notes thereto contained in our Annual Report filed with the SEC on Form 10-K for the year ended July 31, 2014. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the financial statements which would substantially duplicate the disclosures contained in the audited financial statements for the most recent fiscal year ended July 31, 2014, as reported in the Form 10-K, have been omitted.

Reclassifications

Certain prior year amounts have been reclassified to conform with the current presentation.

Principles of consolidation

We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc. (“Penasco”), a Nevada corporation, (ii) Galveston Bay Energy, LLC (“GBE”), a Texas limited liability company, (iii) SPE Navigation I, LLC, a Nevada limited liability company (“SPE”), (iv) Namibia Exploration, Inc. (“NEI”), a Nevada corporation, (v) Hydrocarb Corporation, a Nevada corporation (“HCN”), (vi) Hydrocarb Texas Corporation, a Texas corporation, and (vii) Hydrocarb Namibia Energy (Pty) Limited (“Namibia”), a company chartered in the Republic of Namibia.  In addition, we own 95% of the issued and outstanding share capital of Otaiba Hydrocarb LLC (“Otaiba”), a UAE limited liability corporation. The accompanying consolidated financial statements include the accounts of the entities noted above.  All significant intercompany accounts and transactions have been eliminated in consolidation.

The acquisition of HCN, an entity under common control, on December 9, 2013 (See Note 2 – HCN Acquisition) has resulted in a change in the reporting entity. The consolidated financial statements presented for the periods subsequent to the acquisition include the accounts of HCN and its subsidiaries. As HEC and HCN are under the common control of same shareholder group, the acquired assets and liabilities were recorded at the historical carrying value and the consolidated financial statements were retroactively restated to reflect the Company as if HCN had been owned since the beginning of the earliest period presented.

Noncontrolling interests

Our consolidated financial statements include the accounts of all subsidiaries where we hold a controlling financial interest.  We have a controlling financial interest if we own a majority of the outstanding voting common stock and minority shareholders do not have substantive participating rights, we have significant control over an entity through contractual or economic interests in which we are the primary beneficiary or we have the power to direct the activities that most significantly impact the entity’s economic performance.  The ownership interest in subsidiaries held by third parties are presented in the consolidated balance sheet within equity, but separate from the parent’s equity, as noncontrolling interest.  All significant intercompany balances and transactions have been eliminated in consolidation.

Cash and cash equivalents

Cash and cash equivalents are all highly liquid investments with an original maturity of three months or less at the time of purchase and are recorded at cost, which approximates fair value.

Our functional currency is the United States dollars. Transactions denominated in foreign currencies are translated into their United States dollar equivalents using current exchange rates. Monetary assets and liabilities are translated using exchange rates that prevailed as of the balance sheet date. Non-monetary assets and liabilities are translated using exchange rates that prevailed as of the transaction date. Revenue, if applicable and expenses are translated using average exchange rates over the accounting period. We have had no revenue denominated in foreign currencies. Gains or losses resulting from foreign currency transactions are included in results of operations.

 

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Stock Split

On May 8, 2014, we effected a 1:3 reverse split of our authorized common stock and a corresponding 3:1 reverse split of our outstanding common stock.  All share and per share amounts in this report have been retroactively restated to reflect the reverse split.  This presentation is consistent with the guidance in ASC 260-10-55-12, Earnings per Share, which requires retroactive restatement of earnings per share if a capital structure change due to a stock dividend, stock split or reverse split occurs after the date of the latest balance sheet, but before the release of the financial statements.

Recent accounting pronouncements

In August 2014, the FASB issued Accounting Standard Update No. 2014-15 (“ASU No. 2014-15”),  Presentation of Financial Statements Going Concern (Subtopic 205-40) which requires management to assess an entity's ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. Specifically, ASU 2014-15 provides a definition of the term substantial doubt and requires an assessment for a period of one year after the date that the financial statements are issued (or available to be issued). It also requires certain disclosures when substantial doubt is alleviated as a result of consideration of management's plans and requires an express statement and other disclosures when substantial doubt is not alleviated. ASU No. 2014-15 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, early application is permitted. We are currently evaluating the accounting implication and do not believe the adoption of ASU 2014-15 to have material impact on our consolidated financial statements, although there may be additional disclosures upon adoption.

Other recently issued or adopted accounting pronouncements are not expected to have, or did not have, a material impact on our financial position or results from operations.

Note 2 – HCN Acquisition

The acquisition Agreement provided that HEC would issue 7,470,000 shares of its common stock to the holders of certain rights to acquire HEC stock. These rights were previously issued by HEC as contingent consideration in connection with the acquisition of NEI. The rights had been convertible into HEC common stock based upon HEC market capitalization milestones. The rights were issued to entities deemed related parties to HEC.

 

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HCN had 51% working-interest rights in and operated an unevaluated Namibian concession described in Note 3 – Oil and Gas Properties, below, and provided international oilfield consulting services.  Prior to this acquisition, HEC owned 39% working-interest right in this concession.  With the HCN acquisition, we now own 90% working interest (100% cost responsibility) in the concession.  This 5.3 million-acre concession is located in northern Namibia in Africa.  The concession specifies the following minimum cost responsibilities on an 8/8ths basis:

1)

Initial Exploration Period (expires September 2015): Perform a hydrocarbon potential study, gather and review existing technical data including reprocessing of available seismic lines, and acquire and process 750 kilometers of new 2D seismic data.  The minimum expenditure is $4,505,000.

2)

First Renewal Exploration Period (two years from end of the Initial Exploration Period):  Acquire 200 square kilometers of 3D seismic data, interpret and map the data, design a drilling program, drill one well, conduct an environmental study, and relinquish 25% of the exploration license area.  The minimum expenditure is $17,350,000.

3)

Second Renewal (Production License) Exploration Period (25 years):  Report on reserves and production and conduct an environmental study.  The minimum expenditure is $300,000.

In conjunction with the HCN acquisition, the HEC Board of Directors authorized the immediate issuance of 7,470,000 shares of our common stock to the former owners of NEI. We previously acquired NEI on August 7, 2012 and these 7,470,000 shares had been contingently-issuable consideration for the acquisition of NEI. We issued these shares on December 9, 2013. The original agreement contained market conditions for the issuance of this stock.

Note 3 – Supplemental Cash Flow Information

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 Note 4 – Oil and Gas Properties

 

Evaluated properties

Additions to evaluated oil and gas properties during the six months ended January 31, 2015 consisted mainly of exploration costs, specifically, geological and geophysical costs of approximately $2,271,263.

 

Unevaluated Properties

Namibia, Africa

We own 90% (100% cost responsibility) of our Namibia concession, as described above in Note 2 –Acquisitions.

Additions to unevaluated properties of approximately $182,000 during the Six months ended January 31, 2015 primarily of:

·

Approximately $182,000 of leasehold costs, specifically payment of the annual concession fee to the Government of Namibia. As of January 31, 2015, approximately $2.2 million has been expended towards the initial exploration period.

Note 5 - Impairment

Oil and Gas Properties

We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (“SEC”). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center.

We evaluated our capitalized costs using the full cost ceiling test as prescribed by the Securities and Exchange Commission at the end of each reporting period. As of January 31, 2015 and July 31, 2014, the net book value of oil and gas properties did not exceed the ceiling amount and thus, no impairment of the properties was required. Changes in production rates, levels of reserves, future development costs, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Note 6 – Asset Retirement Obligations

The following is a reconciliation of our asset retirement obligation liability as of January 31, 2015 and July 31, 2014:

 

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Note 7 – Notes Payable

Installment Notes Payable

In May 2012, we entered into a note payable of $18,375 to purchase a vehicle. The note is collateralized by the vehicle. The note carries an interest rate of 6.93% and is payable beginning in June 2012, in 36 installments of $567 per month. The principal balance owed on the note payable was approximately $2,273 and $7,100 as of January 31, 2015 and July 31, 2014, respectively.

In February 2014, we financed our commercial insurance program using a note payable for $403,104. Under the note, we are obligated to make nine payments of $45,718 per month, which include principal and interest, beginning in March 2014. As of January 31, 2015, the note payable balance was approximately $45,000.

Related Party Installment Note Payable

In November 2013, we issued a promissory note for funds received from Mr. Kent P. Watts, Our Chairman, of $100,000. Under the terms of the note, principal on the note was due after one year and incurred interest at 5% per annum payable on a monthly basis. Accrued interest is payable monthly beginning in May 2014, and beginning in August 2014 the principal is due in 36 monthly payments through July 2017. The note is secured by the Company’s assets owned by GBE, subject to any other lien holder's superior rights, if any. In April 2014, the Company entered into a new debt agreement whereby Mr. Watts agreed to loan the Company up to $600,000 at an interest rate of 6.25%. The previous debt of $100,000 was rolled into this new note. Additionally, we borrowed $200,000 from Mr. Watts during April 2014 and $300,000 from Mr. Watts in May 2014. The total balance on the note was $600,000 as of January 31, 2015. As part of the financing agreement with Shadow Tree Capital Management, LLC (as discussed below), this note has been subordinated, and no payments will be made until the Shadow Tree debt has been repaid.

Credit Agreement

Effective August 15, 2014, we entered into a Credit Agreement (the “Credit Agreement”) as borrower, along with Shadow Tree Capital Management, LLC, as agent (the “Agent”), and certain lender parties thereto (the “Lenders”). Pursuant to the Credit Agreement, the Lenders loaned us $4.0 million, which was represented by Term Loan Notes in an aggregate amount of $4,545,454 (the “Notes”), representing an original issue discount of 12%. We also paid the Lenders a structuring fee of $90,909 equal to 2% of the principal amount of the Notes (the “Structuring Fee”) and agreed to reimburse the Lenders for all reasonable and documented fees, costs and expenses associated with the Credit Agreement, which totaled $172,824 in aggregate. Finally, we paid ROTH Capital Partners, LLC, a placement fee of 5% of the total value of the Loans ($227,273), as placement agent and Gary W. Vick, a consulting fee of 1% of the face value of the Loans ($45,455) for consulting services rendered. As a result of the payments above, the net amount of funding received from the Loans was $3,463,539.

 

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The Credit Agreement contains customary representations, warranties, covenants and requirements for the Company to indemnify the Lenders, Agent and their affiliates. The Credit Agreement also includes various covenants (positive and negative) binding upon the Company (and its subsidiaries), including but not limited to, requiring that the Company comply with certain reporting requirements, and provide notices of material corporate events and forecasts to Agent, and prohibiting us from (i) incurring any additional debt; (ii) creating any liens; (iii) making any investments; (iv) materially changing our business; (v) repaying outstanding debt; (vi) affecting a business combination, sale or transfer; (vii) undertaking transactions with affiliates; (viii) amending our organizational documents; (ix) forming subsidiaries; or (x) taking any action not in the usual course of business, in each case except as set forth in the Credit Agreement.

Note 8 – Capital Stock

 

Common Stock Issuances

Pursuant our Credit Agreement, as noted in Note 6 – Notes Payable, during August 2014, we issued 60,000 shares of restricted common stock to the Lenders. The shares were issued pursuant to the terms and conditions of a Stock Grant Agreement, pursuant to which each of the Lenders made certain representations to the Company regarding their financial condition and other items in order for the Company to confirm that an exemption from registration existed and will exist for such issuances.

 

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Receivables for Common Stock

On September 6, 2013, HCN sold 191,667 shares of HEC common stock to an employee of HCN (the nephew of our Chairman and Chief Executive Officer) in exchange for a note receivable in the amount of $1,000,000. HEC acquired this receivable upon its acquisition of HCN. The note is non-interest bearing and is payable only upon the sale of the common stock to a third party or HEC stock being listed on either the NASDAQ or NYSE stock exchanges. We will receive 95% of the proceeds up to $1,000,000 if the underlying stock is sold to a third party. Within 90 days of HEC stock being listed on a major stock exchange, we will receive up to $1,000,000, or the note can be paid earlier at the discretion of the other party. These shares of common stock are held in the name of the investors and are beneficially owned by the investors and the shares are not retrievable by the Company.

On December 4, 2013 HCN sold 619,960 shares of unregistered and restricted HEC common stock in return for a $1,859,879 non-interest bearing note receivable from an  entity in which Michael Watts has a minority interest. HEC acquired this receivable upon its acquisition of HCN. The 619,960 HEC common stock shares were previously issued by HEC to HCN to settle liabilities due by HEC related to the consulting services agreement described below in Note 6 – Notes Payable. The receivable from the individual is due to HEC upon the following conditions: 1) 100% of the proceeds payable from the sale of all or part of the shares by the owner of the shares to a third party; 2) within sixty days of the six month anniversary of the December 4, 2013 stock sale or within sixty days from the date that the shares become unrestricted (whichever is first); or 3) 100% of any remaining balance due within 90 days of HEC being listed on a major stock exchange and whereby the share price is above $6.00 per share. As with the above receivable for common stock, this receivable for the sale of HEC common stock is classified as a receivable for common stock within equity. These shares of common stock are held in the name of the investors and are beneficially owned by the investors and the shares are not retrievable by the Company.

Stock Options and Warrants

As of January 31, 2015, HEC could grant up to 737,706  shares of common stock under the 2013 Stock Incentive Plan (“2013 Plan”). The Plan is administered by the Compensation Committee of the Board of Directors, or in the absence of a Compensation Committee, the full Board of Directors, which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.

Options granted to non-employees

We account for options granted to non-employees under the provisions of ASC 505-50, Equity-Based Payments to Non-employees, and record the associated expense at fair value on the final measurement date. Because there is no disincentive for nonperformance for these awards, the final measurement date occurs when the services are complete, which is the vesting date. For the options granted to non-employees on a graded vesting schedule, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date. When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the date the performance is complete. There were 25,000 options granted to non-employees during the six months ended January 31, 2015. Compensation expense of $112,500 was recognized during the six months ended January 31, 2015. No options have been exercised, and 92,000 expired during the six months ended January 31, 2015.

Options granted to employees

The following table provides information about options granted to employees under our stock incentive plans during the six months ended January 31, 2015 and 2014:

 

		Options				Weighted Average Share Price				Aggregate intrinsic value				Weighted average remaining contractual life (years)
Outstanding at  July 31, 2014			265,333			$	6.81			$					7.95
Granted			25,000				4.50								5.00
Exercised			-				-
Expired			(92,000	)			6.85
Outstanding at January 31, 2015			198,333			$	6.52			$					7.51

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Warrants

Summary information regarding common stock warrants issued and outstanding as of January 31, 2015, is as follows:

 

Warrants granted to related party

During the year ended July 31, 2011, we entered into a consulting agreement with Geoserve Marketing, LLC (“Geoserve”), a company controlled by Michael Watts, who is a related party. Under the terms of the agreement, we granted warrants to purchase 400,000 shares of common stock that have a market condition.  If our common stock attains a five day average closing price of $22.50 per share, 200,000 warrants with an exercise price of $7.50 and an expiration date of February 15, 2016 shall be exercisable (“Warrant B”). If our common stock attains a five day average closing price of $45.00 per share, 200,000 warrants with an exercise price of $7.50 and an expiration date of February 15, 2016 shall be exercisable (“Warrant C”). The fair value of warrants that vest upon the attainment of a market condition must be estimated and amortized over the lower of the implicit or derived service period of the warrants. Previously recognized expense is not reversed in the event of a subsequent decline in the fair value of market condition equity based compensation.  The fair value of the warrants and the derived service period were valued using a lattice model that values the liability of the warrants based on a probability weighted discounted cash flow model. This model is based on future projections of the various potential outcomes. Warrant B and Warrant C were amortized over the derived service periods of 2.08 years and 2.49 years, respectively.  No expense related to these warrants was recognized during the six months ended January 31, 2015, as the expense for the warrants was fully amortized in previously reported periods.

The following reflects the fair value at the end of the derived service for each of the warrants:

 

The following table reflects information regarding Warrant B and Warrant C during the six months ended January 31, 2015 and 2014:

 

Note 9 – Related Party Transactions

During the reporting period we have had transactions as described below with entities controlled by Michael Watts. Michael Watts is the father-in-law of Jeremy Driver, who served as a director and Chief Executive Officer through November, 2013. Additionally, Michael Watts is the brother of Kent Watts, who became the Company’s Chairman of Board of Directors in October 2013. Michael Watts is a related party to the Company by virtue of his relationships with Mr. Driver and with Mr. Watts. Further, two of Michael Watts’ adult children are significant shareholders of HEC’s common stock. Between them, they are beneficial owners of approximately 68% of the outstanding common stock.

A company controlled by Michael Watts purchased a 5% working interest in one of our wells in Galveston Bay.  As of January 31, 2015 and July 31, 2014, this company owed us $100 and $80,468, respectively, in joint interest billings.

During 2011, we entered into a consulting contract with a company controlled by Michael Watts, as detailed in Note 7 – Capital Stock - Warrants.  The contract permits us to terminate the agreement after the first year with thirty days’ notice.  We recognized expense of $0 and $6,754 from this contract during the six months ended January 31, 2015 and 2014, respectively.

 

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During the three months ended October 31, 2013, a company controlled by one of our former officers, Carter E & P, LLC (“Carter”) operated several properties onshore in South Texas, including our producing properties located near the Victoria Barge Canal in Calhoun County, Texas. Although he was not a related party after September 1, 2013, he was a related party during the periods covered by this report. As of January 31, 2015 and July 31, 2014, there were no outstanding related party receivable from Carter.  Revenues generated, lease operating costs, and contractual overhead charges incurred during the time Carter was a related party were as follows:

 

In November 2013, we issued a promissory note for funds received from Mr. Kent Watts, Our Chairman, of $100,000. Under the terms of the note, principal on the note was due after one year and incurred interest at 5% per annum payable on a monthly basis. In April 2014, the Company entered into a new debt agreement whereby Mr. Watts agreed to loan the Company up to $600,000 at an interest rate of 6.25%. The previous debt of $100,000 was rolled into this new note. Additionally, we borrowed $200,000 from Mr. Watts during April 2014 and $300,000 from Mr. Watts in May 2014. The total balance on the note was $600,000 as of January 31, 2015. Accrued interest is payable monthly beginning in May 2014, and beginning in August 2014 the principal is due in 36 monthly payments through July 2017. The note is secured by the Company’s assets owned by GBE, subject to any other lien holder's superior rights, if any. As part of the financing agreement with Shadow Tree, this note has been subordinated, and no payments will be made until the Shadow Tree debt has been repaid.

Note 10 - Commitments and Contingencies

Legal

Environmental

We accrue for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded at their undiscounted value as assets when their receipt is deemed probable.

Letters of Credit

Oil and gas operators in the State of Texas are required to obtain a letter of credit in favor of the Railroad Commission of Texas as security that they will meet their obligations to plug and abandon the wells they operate. We have two letters of credit in the amount of $6,610,000 and $120,000 issued by Green Bank. These letters of credit are collateralized by a certificate of deposit held with the bank for the same amount. We pay a 1.5% per annum fee in conjunction with these letters of credit.

In June 2014, when we renewed the letters of credit, we prepaid the entire years’ interest upfront. We amortize these fees on a straight-line basis. The following table reflects the prepaid balances as of:

 

 

Note 12 – Subsequent Events

Subsequent to January 31, 2015, we raised approximately $1 million through the sale of various convertible promissory notes as described below.

 

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CAUTIONARY STATEMENT ON FORWARD-LOOKING INFORMATION

The Company is including the following cautionary statement for any forward-looking statements made by, or on behalf of, the Company. This quarterly report on Form 10-Q contains “forward looking statements” (as that term is defined in Section 27A(i)(1) of the Securities Act of 1933), including statements concerning plans, objectives, goals, strategies, expectations, future events or performance and underlying assumptions and other statements which are other than statements of historical facts.  Such forward looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward looking statements.  Some of the factors that could cause actual results to differ materially from those expressed in such forward looking statements are set forth in the section entitled “Risk Factors” and elsewhere throughout this Form 10-Q.  Our expectations, beliefs and projections are expressed in good faith and are believed by us to have a reasonable basis, but there can be no assurance that our expectations, beliefs or projections will result or be achieved or accomplished.  We have no obligation to update or revise forward looking statements to reflect the occurrence of future events or circumstances.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

 

Results of Operations

The following table sets out consolidated data for the periods indicated:

Three months ended January 31, 2015 compared to the three months ended January 31, 2014:

 

Statements of operations:

 

		Three Months Ended January 31,								Increase/				%
		2015				2014				(Decrease)				Change
Revenues		$	646,348			$	989,732				(343,384	)			-35	%
Operating expenses
Lease operating expense			913,290				811,127				102,163				13	%
Depreciation, depletion, and amortization			162,166				191,764				(29,598	)			-15	%
Accretion			258,782				244,509				14,273				6	%
Consulting fees - related party			-				-				-
General and administrative expense			980,480				946,325				34,155				4	%
Total operating expenses			2,314,718				2,193,725				120,993				6	%
Loss from operations			(1,668,370	)			(1,203,993	)			(464,377	)			39	%
Consulting and other income (expense)			2,737				(4,940	)			7,677				-155	%
Interest income (expense), net			(279,727	)			(36,854	)			(242,873	)			659	%
Foreign currency transaction gain (loss)			(6,401	)			(28,971	)			22,570				-78	%
Net loss before income taxes			(1,951,761	)			(1,274,758	)			(677,003	)			53	%
Income tax provision			-				-				-
Net loss			(1,951,761	)			(1,274,758	)			(677,003	)			53	%
Less: Net loss attributable to noncontrolling interests			18				(1,888	)			1,906				-101	%
Net loss attributable to Hydrocarb Corporation			(1,951,779	)			(1,272,870	)			(678,909	)			53	%
Deemed dividend on preferred stock			-				(3,019	)			3,019				-100	%
Net loss attributable to Hydrocarb Energy Corp after dividends		$	(1,951,779	)			(1,275,889	)			(675,890	)			53	%

 

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We recorded net loss of $1,951,779, or ($0.09)per basic and diluted common share, during the three months ended January 31, 2015, as compared to a net loss of $ 2,225,697, or ($0.05)per basic and diluted common share, during the three months ended Jaunary 31, 2014.

The changes in results were predominantly due to the factors below:

We continue to evaluate areas where we can reduce costs in lease operating expense and to increase production, which would increase revenues.

Six months ended January 31, 2015 compared to the six months ended January 31, 2014:

                                                            

		Six Months Ended January 31,								Increase/				%
		2015				2014				(Decrease)				Change
Revenues		$	1,851,777			$	2,829,943				(978,166	)			-35	%
Operating expenses
Lease operating expense			2,210,845				1,928,459				282,386				15	%
Depreciation, depletion, and amortization			386,422				493,679				(107,257	)			-22	%
Accretion			560,990				488,485				72,505				15	%
Consulting fees - related party			-				6,754				(6,754	)			-100	%
General and administrative expense			1,923,760				2,738,324				(814,564	)			-30	%
Total operating expenses			5,082,017				5,655,701				(573,684	)			-10	%
Loss from operations			(3,230,240	)			(2,825,758	)			(404,482	)			14	%
Consulting and other income (expense)			6,779				(30,266	)			37,045				-122	%
Interest income (expense), net			(507,504	)			21,338				(528,842	)			-2478	%
Foreign currency transaction gain (loss)			(1,642	)			(30,626	)			28,984				-95	%
Net loss before income taxes			(3,732,607	)			(2,865,312	)			(867,295	)			30	%
Income tax provision			-				(4,599	)			4,599				-100	%
Net loss			(3,732,607	)			(2,869,911	)			(862,696	)			30	%
Less: Net loss attributable to noncontrolling interests			(1,305	)			(3,360	)			2,055				-61	%
Net loss attributable to Hydrocarb Corporation			(3,731,302	)			(2,866,551	)			(864,751	)			30	%
Deemed dividend on preferred stock			-				(34,254	)			34,254				-100	%
Net loss attributable to Hydrocarb Energy Corp after dividends			(3,731,302	)		$	(2,900,805	)			(830,797	)			29	%

                                                         

We recorded net loss of $3,731,302, or ($0.18)per basic and diluted common share, during the six months ended January 31, 2015, as compared to a net loss of $ 2,866,551, or ($0.10)per basic and diluted common share, during the six months ended January 31, 2014.

The changes in results were predominantly due to the factors below:

 

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Liquidity and Capital Resources

The following table sets forth our cash and working capital as of January 31, 2015 and July 31, 2014, respectively:

 

At January 31, 2015, we had $266,646 of cash on hand and a working capital of $(3,338,050).

 

Operation Plans and Focus

In Galveston Bay, Texas we plan to continue enhancing the production from our four productive fields. Our 2014 Production Enhancement Program has included primarily reworking, infrastructure improvements, and recompletions, as well as drilling, as to exploit the known reserves in at least 18 wells. Internal estimates show the projects are showing success, and as of February 2015 over production of February 2014, there has been an approximately 400% increase in production. Due to the fact that a large proportion of current operating costs in Galveston Bay are fixed it is expected that as production grows an increasing percentage of the revenue will contribute to positive cash flow. We plan to fund these projects as long as working capital and cash-flow permits and pending success of previous projects. If we are able to secure either bank or equity financing in the near future, this development plan can be accelerated.

 

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Our plan of operations over the next nine months is to increase cash flow upon one or more of the following occurring:

Subsequent to January 31, 2015, we raised approximately $1 million through the sale of various convertible promissory notes as described below.

 

Critical Accounting Policies

The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission (“SEC”). The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.

We regularly evaluate the accounting policies and estimates that we use to prepare our consolidated financial statements. In general, our estimates are based on historical experience, on information from third party professionals, and on various other assumptions that are believed to be reasonable under the facts and circumstances. Actual results could differ from those estimates made by management.

We believe that our critical accounting policies and estimates include the accounting for oil and gas properties, long-lived assets reclamation costs, and accounting for stock-based compensation.

Oil and Natural Gas Properties

We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.

 

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Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization.

We assess all items classified as unevaluated property on at least an annual basis for inclusion in the amortization base. 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. During any period in which these factors indicate that there would be impairment, or if proved reserves are assigned to a property, the cumulative costs incurred to date for such property are transferred to the amortizable base and are then subject to amortization.

Capitalized costs included in the amortization base are depleted using the units of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.

The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to prove oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.

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.

Asset Retirement Obligations

We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gas gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will accordingly update our assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gas gathering systems as these obligations are incurred.

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 recognize the cost associated with share-based awards that have a graded vesting schedule on a straight-line basis over the requisite service period of the entire award.

Off-Balance Sheet Arrangements

We have not entered into any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes of financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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Pursuant to Item 305(e) of Regulation S-K (§ 229.305(e)), the Company is not required to provide the information required by this Item as it is a “smaller reporting company,” as defined by Rule 229.10(f)(1).

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Principal Executive Officer has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, our Principal Executive Officer has concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were not effective, due to the deficiencies in our internal control over financial reporting as described in our Annual Report on Form 10-K for our fiscal year ended July 31, 2014, which deficiencies have not yet been remedied.

Internal Control over Financial Reporting

During the six months ended January 31, 2015, we continued to implement and document entity-level controls, formalize risk assessment processes and adopt additional policies and procedures to improve our internal control over financial reporting.

 

Part II Other Information

Item 1.

Legal Proceedings

 

As of anuary 31, 2015, we were a party to the following legal proceedings:

Item 1A.

Risk Factors

For information regarding our risk factors see the risk factors disclosed in Item 1A of our Annual Report on Form 10-K filed on November 13, 2014. There have been no material changes from the risk factors previously disclosed in such Annual Report as of the date of this report, other than the risk factors provided below:

In December 2013, the Board of Directors approved, and the Company filed a Certificate of Designation with the Secretary of State of Nevada to create a Series A 7% Convertible Voting Preferred Stock (“Series A Preferred”).  The designation authorized up to 10,000 shares of Series A Preferred. Pursuant to the designation, the Series A Preferred has a stated value of $400 per share, pays annual dividends at 7%, is convertible into the Company’s common stock, at the holder’s option, at a conversion rate of $6.00 per share, and is neither redeemable nor callable. The designation provides that the Series A Preferred shareholders may vote their common stock equivalent voting power (i.e., the number of shares of common stock which the Series A Preferred stock shares convert into). A total of 8,188 shares of Series A Preferred Stock were issuable to Kent Watts, our Chief Executive Officer, in connection with the acquisition of HCN on December 9, 2013.

In connection with certain recent due diligence undertaken by the Company, it has come to the attention of management, that although the Company previously believed, on advice of prior counsel, that the Board of Directors of the Company had the authority under the Company’s Articles of Incorporation, to unilaterally authorize preferred stock, that under applicable Nevada law, unless such preferred stock is specifically authorized in a Nevada corporation’s articles no preferred stock can be designated or issued.  As such, our Board of Directors did not have authority under the Articles of Incorporation, as amended, and applicable Nevada law to designate the Series A Preferred or to file such designation with the Secretary of State of Nevada. Consequently, we now believe that the Series A Preferred is not validly issued or outstanding and the filing of the Series A Preferred designation was invalid and had no legal effect.

Notwithstanding the above, the documentation relating to the designation of the Series A Preferred was filed with and accepted by the Secretary of State of Nevada and the Company has previously been treating the Series A Preferred as validly issued and outstanding. For example, during the year ended July 31, 2014, the holder of the Series A Preferred Stock purportedly earned dividends of $150,548 on such securities.  As of July 31, 2014, these dividends have not been accrued as liabilities since they were not declared by the Company.

Although the Company took action in good faith, based on the advice of prior counsel, in connection with the designation of the Series A Preferred, following the date of this filing, the Company plans to promptly take steps to hold a shareholders meeting to seek shareholder approval to amend the Articles of Incorporation to properly authorize preferred stock and provide the Board of Directors the ability in their discretion to designate such preferred stock, and may further request shareholder approval and ratification of the specific terms of the terms of the prior Series A Preferred. Assuming shareholder approval of the authorization of preferred stock, and the Board of Director’s ability to designate such preferred stock, and/or the actual terms of the Series A Preferred, the Company will re-file the Series A Preferred designation with the Secretary of State of Nevada. The Company plans to provide the Series A Preferred holder (Mr. Watts), upon amendment of the Articles of Incorporation to authorize preferred stock and the designation of the Series A Preferred, the equivalent rights as he would have held and be due (including accrued and unpaid dividends) had the Series A Preferred been validly designated and issued to Mr. Watts in December 2013. Due to the fact that the prior filing of the Series A Preferred Stock and actions taken in connection therewith were on advice of prior counsel and made in good faith and our current Chief Executive Officer, Mr. Watts, was to be the sole recipient of the Series A Preferred, we believe that our liability to Mr. Watts for our failure to properly designate and issue such Series A Preferred stock is minimal; however, we may in the future, enter into amendments or addendums to the December 2013 closing documents with Mr. Watts to clarify the current status of the Series A Preferred as well as certain other matters.

 

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We have various outstanding convertible notes which are convertible into shares of our common stock at a discount to market.

As described above under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Recent Funding Transactions”, we sold various convertible promissory notes in February and March 2015. Specifically, we sold an 8% Convertible Redeemable Note to LG Capital Funding, LLC in the amount of $105,000; an 8% Convertible Redeemable Note to Adar Bays, LLC in the amount of $105,000; a Convertible Promissory Note in the principal amount of $350,000 to KBM Worldwide, Inc.; a 10% Convertible Note to JSJ Investments Inc. in the amount of $137,000; and a Secured Convertible Promissory Note to Typenex Co-Investment, LLC in the amount of $350,000 (collectively, the “Convertible Notes”). The conversion prices of the Convertible Notes vary from between 50% to 80% of the market value of our common stock, subject in many cases to antidilution and other rights. As a result, any conversion of the Convertible Notes and sale of shares of common stock issuable in connection with the conversion thereof will likely cause the value of our common stock, if any, to decline in value, as described in greater detail under the Risk Factors below. Notwithstanding the above, we plan to repay the Convertible Notes in full before any conversions take place.

The issuance and sale of common stock upon conversion of the Convertible Notes may depress the market price of our common stock.

If sequential conversions of the Convertible Notes and sales of such converted shares take place, the price of our common stock may decline, and as a result, the holders of the Convertible Notes will be entitled to receive an increasing number of shares in connection with conversions, which shares could then be sold in the market, triggering further price declines and conversions for even larger numbers of shares, to the detriment of our investors. The shares of common stock which the Convertible Notes are convertible into may be sold without restriction pursuant to Rule 144. As a result, the sale of these shares may adversely affect the market price, if any, of our common stock.

In addition, the common stock issuable upon conversion of the Convertible Notes may represent overhang that may also adversely affect the market price of our common stock. Overhang occurs when there is a greater supply of a company’s stock in the market than there is demand for that stock. When this happens the price of the company’s stock will decrease, and any additional shares which shareholders attempt to sell in the market will only further decrease the share price. The Convertible Notes will be convertible into shares of our common stock at a discount to market as described above, and such discount to market provides the holders with the ability to sell their common stock at or below market and still make a profit. In the event of such overhang, the note holders will have an incentive to sell their common stock as quickly as possible. If the share volume of our common stock cannot absorb the discounted shares, then the value of our common stock will likely decrease. Notwithstanding the above, we plan to repay the Convertible Notes in full before any conversions take place.

The issuance of common stock upon conversion of the Convertible Notes will cause immediate and substantial dilution.

The issuance of common stock upon conversion of the Convertible Notes will result in immediate and substantial dilution to the interests of other stockholders since the holders of the Convertible Notes may ultimately receive and sell the full amount of shares issuable in with the conversion of such Convertible Notes. Although certain of the Convertible Notes may not be converted if such conversion would cause the holders thereof to own more than 4.99% or 9.99% of our outstanding common stock, this restriction does not prevent the holders of the Convertible Notes subject to such restrictions from converting some of their holdings, selling those shares, and then converting the rest of its holdings, while still staying below the 4.99% limit. In this way, the holders of the Convertible Notes could sell more than any applicable ownership limit while never actually holding more shares than the applicable limits allow. If the holders of the Convertible Notes choose to do this, it will cause substantial dilution to the then holders of our common stock. Notwithstanding the above, we plan to repay the Convertible Notes in full before any conversions take place.

 

 

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Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

 

During the six months ended January 31, 2015, we issued an aggregate of 100,000 shares of common stock to consultants for services rendered. We valued these transactions at approximately $266,722.

 

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

In September 2014 our Chief Executive Officer, Kent P. Watts, traveled to Abu Dhabi and met with the Board of Directors of Otaiba Hydrocarb LLC, of which we own 95%. His goal was to proceed with oil company registration work that would allow Otaiba to receive bids on oilfield services work with the hopes of developing profitable business, which has been the plan since the subsidiary was established. Instead of being able to proceed with the business plan, the Company’s partner in Otaiba made it clear that they wanted more control over management of the subsidiary while still requiring the Company to fund ongoing expenses. As such, an impasse was created between the Company and its partners in Otaiba. Together with consideration for the severe drop in oil prices, the Board of Directors made the decision to cease operations in Otaiba in favor of our focus in oilfield services to be developed domestically. Thus, during the quarter ended January 31, 2015, the decision was made to close the office in the U.A.E. and not to continue its operations thereby reducing cash expense obligations that we have had in the past but no longer have. The accounting effect of this shutdown is minimal.

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Item 6.

Exhibits

See the Exhibit Index following the signature page to this Quarterly Report on Form 10-Q for a list of exhibits filed or furnished with this report, which Exhibit Index is incorporated herein by reference.

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

HYDROCARB ENERGY CORP.

 

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EXHIBIT INDEX

*	Filed herewith.

**	Furnished herewith.

 

# XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

 

 

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Exhibit 23.1

 

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Exhibit 31.1

 

Date:	March 23, 2015
By:	/s/ Kent P. Watts
	Kent P. Watts
	Chief Executive Officer and a director
	(Principal Executive Officer)

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Exhibit 31.2

 

Date:	March 23, 2015
By:	/s/ Christine P. Spencer
	Christine P. Spencer
	Chief Accounting Officer
	(Principal Accounting Officer)

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Exhibit 32.1

 

CERTIFICATIONS PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2001

(18 U.S.C SECTION 1350)

 

In connection with the Quarterly Report of Hydrocarb Energy Corp, on Form 10-Q for the quarter ended January 31, 2015, as filed with the Securities and Exchange Commission (the "Report"), Kent P. Watts, Chief Executive Officer and Christine P. Spencer, Chief Accounting Officer of Hydrocarb Energy Corp., do hereby certify, pursuant to 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350), that to his or her knowledge:

 

(1)         The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)         The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

Date:

March 23, 2015

 

A signed original of this written statement required by Section 906 or other document authenticating, acknowledging, or otherwise adopting the signatures that appear in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

 

 

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Exhibit 99.1

 

January 31, 2015

 

Hydrocarb Energy Corporation

800 Gessner Rd., Suite 375

Houston, TX 77024

Chief Executive Officer

Re: Oil, Condensate, and Natural Gas Reserves

SEC Non-Escalated Analysis

Hydrocarb Energy Corporation

As of January 31, 2015

Gentlemen:

At the request of Hydrocarb Energy Corporation (“Hydrocarb”), the firm of Ralph E. Davis Associates Inc. (“Davis”) has prepared an evaluation of the oil, natural gas, and natural gas liquid reserves on leaseholds in which Hydrocarb has certain interests.  The purpose of this report is to present a summary of the proved developed producing, proved developed behind pipe, proved shut-in, and proved undeveloped reserves that in our opinion meet the criteria for proved reserve volumes in keeping with the directives of the Securities and Exchange Commission as detailed later in this report.

Davis has evaluated 100% of Hydrocarb’s proved developed producing, proved developed behind pipe, proved shut-in, and proved undeveloped properties, all of which are located in either Chambers or Galveston Counties of Texas in the United States. We have prepared these estimates of the reserves, future production and income attributable to the subject interests with an effective date of January 31, 2015, having completed the evaluation of said estimate of reserves based upon the information presented within this report, on January 27, 2015.

The reserves associated with this review have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Part 210—Form and Content of and Requirements for Financial Statements, Securities Act of 1933, Securities Exchange Act of 1934, Public Utility Holding Company Act of 1935, Investment Company Act of 1940, Investment Advisers Act of 1940, and Energy Policy and Conservation Act of 1975, under Rules of General Application § 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975. A summation of these definitions is included as a portion of this letter.

We have also estimated the future net revenue and discounted present value associated with these reserves as of January 31, 2015, utilizing a scenario of non-escalated product prices as well as non-escalated costs of operations, i.e., prices and costs were not escalated above current values as detailed later in this report. The present value is presented for your information and should not be construed as an estimate of the fair market value.

 

 

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The results of our study related to our estimate of the Total Proved Reserves attributable to Hydrocarb and remaining to be produced as of January 31, 2015 are as follows:

                                           

Estimated Proved Reserves

Net to Hydrocarb Energy Corporation

SEC Non-Escalated Analysis

As of January 31, 2015

                                                                 

		Proved
		Producing				Shut In				Non-Producing				Behind Pipe				Undeveloped				Field Expense				Total
Net Reserves
Oil/Condensate-MBbls			431.0				31.4				46.9				115.5				607.3				-				1,232.0
Gas-MMCF			2,061.8				519.8				775.7				2,089.0				6,216.1				-				11,662.3
Income Data (M$)
Future Gross Revenue		$	48,446.4			$	5,194.1			$	7,559.1			$	19,591.4			$	81,714.8			$	-			$	162,505.8
Ad Valorem Tax		$	1,211.2			$	129.8			$	189.0			$	489.8			$	2,042.9			$	-			$	4,062.6
Severance Tax		$	2,493.8			$	306.4			$	443.0			$	1,164.0			$	4,522.8			$	-			$	8,930.0
Operating Costs		$	590.9			$	120.4			$	388.1			$	636.7			$	3,074.6			$	-			$	4,810.8
Capital Costs		$	250.0			$	1,425.0			$	-			$	984.4			$	14,650.0			$	4,731.1			$	22,040.5
Future Net Income (FNI)		$	43,900.6			$	3,212.4			$	6,539.0			$	16,316.5			$	57,424.4			$	(40,987.5	)		$	86,405.4
FNI @ 10%		$	32,178.7			$	2,144.3			$	5,156.3			$	8,302.5			$	30,347.9			$	(22,184.6	)		$	55,945.1

                                              

*(Expenses are applied on a field wide basis.  Therefore, the net undiscounted and discounted income (10%) has been adjusted.  The values have been adjusted by application of each category’s share of the expense as a percent of its share of the unadjusted income.)  Note:  There may be differences in the addition as a result of computer program rounding of numbers.

Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil.  Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located.

A summary presentation by reserve category at the scheduled price scenario is included behind the economic summary analysis tab.

Discussion

The scope of this study was to review basic information compiled by and prepare estimates of the proved reserves attributable to the interests of Hydrocarb.  Reserve estimates were prepared by Davis using acceptable evaluation principles for each source and were based in large part on the basic information supplied by Hydrocarb.

The quantities presented herein are estimated reserves of oil and natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under current economic conditions with reasonable certainty.  Proved undeveloped locations are scheduled to be drilled such that the investment cost will be fully recovered prior to recovery of estimated reserve volumes.

The evaluated properties are operated by a Hydrocarb subsidiary operating company.  All proved developed producing properties were reviewed for this evaluation and all requested data was made available by Hydrocarb.  Data provided includes seismic, well logs, sub-surface maps, analogous well data, timing of future development, drilling and investments.

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Certain properties have been drilled, completed, and previously produced.  Many of these contain additional reserves in intervals not yet completed within an existing wellbore and have been classified as proved behind pipe.  All of these properties are considered to have recoverable reserves and are scheduled to be placed on production at a future time.

Certain properties which have been drilled are currently shut-in.  They are considered to have recoverable reserves and are scheduled to be placed on production at a future time.  These properties will require remedial action before they can be restored to production.

Reserves classified as undeveloped are scheduled for future drilling beginning in 2015.  The undrilled locations have been reviewed on an individual well location basis.  The estimates of these recoverable reserves are based on volumetric estimates.

 This evaluation has been prepared in accordance with the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” as proclaimed by the Society of Petroleum Engineers”, the SPE Standards.

Data Source

Basic well and field data used in the preparation of this report were furnished by Hydrocarb or were obtained from commercial sources or from Davis’ own database of information. Records as they pertain to factual matters such as acreage controlled the number and depths of wells, reservoir pressure and/or production history, the existence of contractual obligations to others, and similar matters were accepted as presented.

Additionally, the analyses of these properties utilized not only the basic data on the subject wells but also data on analogous properties as provided.  Well logs, ownership interest, revenues received from the sale of products and operating costs were furnished by Hydrocarb. No physical inspection of the properties was made nor any well tests conducted.

Operating cost data were provided by Hydrocarb and were utilized to estimate the direct cost of operation for each property or producing unit.  Certain historical costs of operation are charged against a producing unit or group of wells in addition to any individual well costs that may be scheduled for an area.  Development costs for new wells to be drilled, wells to be worked over to return intervals to production, anticipated costs to provide for significant field operation, and facility changes were provided by Hydrocarb and are reported to be based upon recent field activity.

Ownership

Ownership interests in the subject properties have been furnished by Hydrocarb and accepted by Davis as accurate without independent verification.

 

Texas Registered Engineering Firm F-1529

 

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Reserve Estimates

The estimate of reserves included in this report is based primarily upon production history or analogy with wells in the area producing from the same or similar formations.  In addition to individual well production history, geological and well test information, when available, were utilized in the evaluation.  Individual well production histories were analyzed and forecast until a calculated economic limit.

Reserves for the behind pipe categories were estimated using volumetric methods which consolidated well log, sidewall core, and subsurface mapping. Reserves for Fishers Reef, N. Point Bolivar, Red Fish Reed, and Trinity Bay Fields were prepared on a field wide basis.  They are estimated to the limit of profitable operations for each field.

The accuracy of reserve estimates is dependent upon the quality of available data and upon the independent geological and engineering interpretation of that data.  Reserve volumes presented in this report are based upon the available data and are calculated using all methods and procedures as we considered necessary under the circumstances to prepare this report and are believed to be reasonable; however, future reservoir performance may justify revision of these estimates.  The various methods and procedures used in the evaluation of the subject properties are considered appropriate for an audit of the subject properties.

It should be noted that all reserve estimates involve an assessment of uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities. The uncertainty depends primarily on the amount of reliable geological and engineering data available at the time of the estimate along with the interpretation of these data. The reserves have been determined using methods and procedures widely accepted within the industry and are believed to be appropriate for the purposes of this report. In our opinion, we used all methods and procedures necessary under the circumstances to prepare this report.

Regulations in the Oil and Gas industry are constantly changing to meet new safety and environmental concerns, in addition to the possibility of some market regulations which have occasionally occurred historically. State, Local or Federal Regulations, such as upon hydraulic fracturing, or drill/production site security and safety, environmental regulations of spills noxious emissions, greenhouse gases, and drill site location, wildlife protections and extensive permitting processes, sometimes with multiple agencies or governments, in the future may all adversely affect the ability of the Registrant to recover the estimated reserves, as well as potentially rendering the reserves uneconomic, in certain, as yet undetermined, circumstances. To the best of the engineers belief, none of the reserves described in this report are negatively impacted as of the date of this report, by any such current regulations.

Producing Rates

For the purpose of this report, estimated reserves are scheduled for recovery primarily on the basis of actual producing rates or appropriate well test information. They were prepared giving consideration to engineering and geological data such as reservoir pressure, anticipated producing mechanisms, the number and types of completions, as well as past performance of analogous reservoirs.

 

Texas Registered Engineering Firm F-1529

 

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These and other future rates may be subject to regulation by various agencies, changes in market demand or other factors; consequently, reserves recovered and the actual rates of recovery may vary from the estimates included herein.  Scheduled dates of future well completions may vary from that provided by Hydrocarb due to changes in market demand or the availability of materials and/or capital; however, the timing of the wells and their estimated rates of production are reasonable and consistent with established performance to date.

Pricing Provisions

Prices received for products sold, adjustments due to the BTU content of the gas, shrinkage for transportation, measuring or the removal of liquids, the liquid yield from gas processed, etc., were provided by Hydrocarb and were accepted as presented.

The unit prices used throughout this report for crude oil, condensate, and natural gas are based upon the appropriate prices in effect the first trading of each month from February 2014 through January 2015 and averaged for the year.

Crude Oil, Condensate and/or Natural Gas Liquids – The unit price used throughout this report for crude oil and condensate is based upon the average of prices for the twelve month period as indicated above.

An average crude oil price of $91.18 per barrel represents the effective average crude oil price utilized in the evaluation. This scheduled price for 2015 was held flat throughout the remaining producing life of the properties.  Prices for the liquid reserves scheduled for initial production at some future date were estimated using this same price.  Oil prices were adjusted for price differentials.  The average price realized for liquid reserves, crude oil and condensate, over the producing life of the properties, was $91.18 per barrel, and represents the combined effect due to the adjustments for location and quality differentials such as transportation, quality and gravity.

Natural Gas – The unit price used throughout this report for natural gas is based upon the average of prices for the twelve month period as indicated above.   An average gas price of $4.34 per MMBTU represents the effective average natural gas price utilized in the evaluation.   The scheduled price for 2015 was held flat throughout the remaining producing life of the properties.  Prices for natural gas reserves scheduled for initial production at some future date were estimated using this same price.  Gas prices were adjusted for BTU content and price differentials.  The average price realized for natural gas reserves over the producing life of the properties, was $4.30 per MLMBTU, and represents the combined effect due to the adjustments for location and quality differentials such as transportation and the BTU (heating value) of the gas

Future Net Income

Future net income is based upon gross income from future production, less direct operating expenses and applicable provincial taxes.  Estimated future capital for development was also deducted from gross income at the time it will be expended.  No allowance was made for depletion, depreciation, income taxes, or administrative expense.

Direct lease operating expense includes direct cost of operations of each lease or an estimated value for future operations based upon analogous properties.  Lease operating expenses and/or capital costs for drilling and/or major workover expense were held flat throughout the producing life of the properties.  Abandonment costs were deducted at the end of the economic life of the fields.

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Future net income has been discounted for present worth at values ranging from 0 to 100 percent using continuous discounting.  In this report, the future net income is discounted at a primary rate of ten (10.0) percent.

General

Hydrocarb Energy Corporation has provided access to all of its accounts, records, geological and engineering data, reports, and other information as required for this audit. The ownership interests, product classifications relating to prices, and other factual data were accepted as furnished without verification.

No consideration was given in this report to potential environmental liabilities which may exist, nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.

Neither Ralph E. Davis Associates, Inc. nor any of its employees have any interest in Hydrocarb or the properties reported herein.  The employment and compensation to make this study are not contingent on our estimate of reserves. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SEC standards.

This report has been prepared for public disclosure by Hydrocarb in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please feel free to contact us if we can be of further service.

We appreciate the opportunity to be of service to you in this matter and will be glad to address any questions or inquiries you may have.

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Securities and Exchange Commission

Definitions of Reserves

 

The following information is taken from the United States Securities and Exchange Commission:

PART 210—FORM AND CONTENT OF AND REQUIREMENTS FOR FINANCIAL STATEMENTS, SECURITIES ACT OF 1933, SECURITIES EXCHANGE ACT OF 1934, PUBLIC UTILITY HOLDING COMPANY ACT OF 1935, INVESTMENT COMPANY ACT OF 1940, INVESTMENT ADVISERS ACT OF 1940, AND ENERGY POLICY AND CONSERVATION ACT OF 1975

Rules of General Application

§ 210.4-10   Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975.

Reserves

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Proved Oil and Gas Reserves

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

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

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Securities and Exchange Commission	Page 2
§ 210.4-10   Definitions (of Reserves)
Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter

 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

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(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Developed Oil and Gas Reserves

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped Oil and Gas Reserves

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

Additional Definitions:

Deterministic Estimate

The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Probabilistic Estimate

The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

Reasonable Certainty

If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

 

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I, Allen C. Barron, of 1717 St. James Place, Suite 460, Houston, Texas 77056 hereby certify:

1.

I am an employee of Ralph E. Davis Associates, Inc., that has prepared an evaluation and certification of the oil, natural gas and natural gas liquid reserves on specific leaseholds in which Hydrocarb Energy Corporation has certain interests.  The effective date of this evaluation is January 31, 2015.

2.

I am Licensed Professional Engineer by the State of Texas, P.E. License number 48284.

3.

I attended the University of Houston in Houston, Texas and graduated with a Bachelor of Science Degree in Chemical Engineering with a Petroleum Engineering option in 1968.  I have in excess of forty-six years of experience in the petroleum industry of which over thirty-six years of experience are in the conduct of evaluation and engineering studies relating to both domestic U.S. oil and gas fields and international energy assets.

4.

I have prepared reserve evaluation studies and reserve audits for public and private companies for the purpose of reserve certification filings in foreign countries, domestic regulatory filings, financial disclosures, and corporate strategic planning.  I personally supervised and participated in the evaluation of the Hydrocarb Energy Corporation properties that are the subject of this report.

5.

I do not have, nor do I expect to receive, any direct or indirect interest in the securities of Hydrocarb Energy Corporation or any affiliated organizations.

6.

A personal field inspection of the properties was not made, however, such an inspection was not considered necessary in view of the information available from public information, records, and the files of the operator of the properties.

Signed:  January 31, 2015

 

 

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Date :      02/03/2015    8:48:33AM

Total

Project Name :      HYDROCARB ENERGY 01/31/2015	As Of Date :	01/31/2015
Partner :                 All Cases	Discount Rate (%) :	10.00
Case Type :            GRAND TOTAL CASE	All Cases

SEC REPORT

 

Cum Oil (Mbbl) :	4,109.48
Cum Gas (MMcf) :	42,197.54

Year	Gross Oil	Gross Gas	Net Oil	Net Gas		Oil Price	Gas Price	Oil Revenue	Gas Revenue	Misc. Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)		($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2015	124.51	1,288.67	93.51	822.32		91.18	4.34	8,526.71	3,569.45	0.00
2016	148.53	3,313.17	113.37	1,962.77		91.18	4.35	10,336.88	8,539.51	0.00
2017	246.16	1,960.80	194.24	1,306.12		91.18	4.30	17,711.59	5,615.89	0.00
2018	229.34	2,289.17	181.75	1,560.05		91.18	4.29	16,572.00	6,688.47	0.00
2019	183.27	1,682.52	145.17	1,132.70		91.18	4.31	13,236.56	4,878.84	0.00
2020	146.82	1,190.42	116.33	795.71		91.18	4.31	10,606.82	3,429.35	0.00
2021	117.98	844.46	93.52	559.69		91.18	4.31	8,526.97	2,413.75	0.00
2022	94.82	608.58	75.18	397.84		91.18	4.32	6,855.26	1,716.99	0.00
2023	53.88	404.77	42.31	282.68		91.18	4.32	3,857.47	1,220.59	0.00
2024	43.18	291.25	33.91	203.18		91.18	4.32	3,091.79	878.21	0.00
2025	36.71	253.48	29.52	180.00		91.18	4.30	2,691.90	774.19	0.00
2026	28.34	491.98	22.89	353.07		91.18	4.26	2,087.00	1,504.40	0.00
2027	32.02	732.07	25.79	527.79		91.18	4.25	2,351.83	2,242.71	0.00
2028	33.52	1,034.13	26.82	746.01		91.18	4.24	2,445.85	3,166.16	0.00
2029	30.86	745.16	24.89	539.93		91.18	4.24	2,269.83	2,290.06	0.00
Rem	15.89	403.02	12.82	292.45		91.18	4.24	1,169.33	1,239.39	0.00
Total	1,565.85	17,533.66	1,232.02	11,662.31		91.18	4.30	112,337.78	50,167.97	0.00
Ult	5,675.32	59,731.19