10-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(AMENDMENT No. 1)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended July 31, 2014

☐ 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

HYDROCARB ENERGY CORP

(Exact name of registrant as specified in its charter)

Nevada	30-0420930
(State or other jurisdiction of incorporation of organization)	(I.R.S. Employer Identification No.)
800 Gessner, Suite 375, Houston, TX	77024
(Address of Principal Executive Offices)	(Zip Code)

(713) 970-1590

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, Par Value $0.001

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ☐   No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of Section 15(d) of the Act.  Yes ☐  No ☒

Indicate by check mark whether the registrant (1) 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 ☒   No ☐

Indicate by checkmark 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ☒   No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

Indicate by checkmark 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.

Large accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer ☐ (do not check if a smaller reporting company)	Smaller reporting company ☒

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐   No ☒ 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed by reference to the price at which the registrant’s common equity was last sold, as of January 31, 2014 the last day of the registrant’s most recently completed second fiscal quarter) was approximately $22,570,168. 

The registrant had 21,186,602 shares of common stock outstanding as of October 22, 2014.

EXPLANATORY NOTE

On November 13, 2014, Hydrocarb Energy Corporation (the “Company”) filed its Annual Report on Form 10-K for its fiscal year ended July 31, 2014 (the “Original Form 10-K”). Subsequent to the filing of the Original Form 10-K, the Company became aware of various issues (described in greater detail below) relating to such filing and the Company is hereby amending its Original Form 10-K. Revisions to the Original Form 10-K are made in the following areas.

Item 1.	Changes in Proved Undeveloped Reserves	Expanded explanation related to the revision in previous estimate of proved undeveloped reserves for the year ended July 31, 2014.
Item 1.	Production and Price History	Edited description of Total (BOE) to Total (Mcfe) and adjusted Totals.
Item 1.	Acreage	Updated table of gross and net developed and undeveloped acreage.
Item 1.	Acreage	Expanded disclosure language related to acreage held related to total proved reserves and total proved undeveloped reserves.
Item 1.	Acreage	Expanded disclosure regarding acreage to include information related to acreage held related to onshore petroleum concessions located in the republic of Namibia.
Item 1.	Acreage	Expanded language to clarify further expirations dates related to leases of material amounts of undeveloped acreage.
Item 7.	Plan of Operations	Addition of language related to the termination of oil and gas activities within the U.A.E.
Item 8.	Note 15 - Subsequent Events	Added language relating to the termination of oil and gas activities in the U.A.E.
Item 8.	Note 16 – Supplemental Oil and Gas Information (Unaudited)	Expanded disclosure related to reasons and circumstances for changes in “Revisions of previous estimates” for the years ended July 31, 2014 and 2013, respectively.
Item 8.	Note 16 – Supplemental Oil and Gas Information (Unaudited)	Expanded disclosure to explain differences between total proved undiscounted future net income shown in the reserve report and the disclosure in Note 16 of future cash inflows less the future production and future development costs for each of the periods ending July 31, 2014 and 2013, respectively.
Item 15.	Exhibit 99.1	Amended filing to include “Certificate of Qualification” of technical person primarily responsible for overseeing the preparation of the reserve report.
Item 15.	Exhibit 99.1	Addition of paragraph stating the assumptions, data, methods, and procedures are appropriate for the purposes served by the reserve report.

This Amendment No. 1 to the Original Form 10-K replaces and supersedes the Original Form 10-K filed with the Securities and Exchange Commission on November 13, 2014. Readers should disregard the Original Form 10-K in its entirety.

This Form 10-K/A speaks as of the original filing date of the Original Form 10-K, does not reflect events that may have occurred subsequent to the original filing date, and does not modify or update in any way disclosures made in the Original Form 10-K, other than as noted above.

FORWARD LOOKING STATEMENTS

This annual report contains forward-looking statements that involve risks and uncertainties. Any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may”, “should”, “expect”, “plan”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential” or “continue”, the negative of such terms or other comparable terminology. In evaluating these statements, you should consider various factors, including the assumptions, risks and uncertainties outlined in this annual report under “Risk Factors”. These factors or any of them may cause our actual results to differ materially from any forward-looking statement made in this annual report. Forward-looking statements in this annual report include, among others, statements regarding:

● our capital needs;

● business plans; and

● expectations.

While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding future events, our actual results will likely vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested herein. Some of the risks and assumptions include, but are not limited to:

● our need for additional financing;

● our exploration activities may not result in commercially exploitable quantities of oil and gas on our properties;

● the risks inherent in the exploration for oil and gas such as weather, accidents, equipment failures and governmental restrictions;

● our limited operating history;

● our history of operating losses;

● the potential for environmental damage;

● the competitive environment in which we operate;

● the level of government regulation, including environmental regulation;

● changes in governmental regulation and administrative practices;

● our dependence on key personnel;

● conflicts of interest of our directors and officers;

● our ability to fully implement our business plan;

● our ability to effectively manage our growth; and

● other regulatory, legislative and judicial developments.

We advise the reader that these cautionary remarks expressly qualify in their entirety all forward-looking statements attributable to us or persons acting on our behalf. Important factors that you should also consider, include, but are not limited to, the factors discussed under “Risk Factors” in this annual report.

The forward-looking statements in this annual report are made as of the date of this annual report and we do not intend or undertake to update any of the forward-looking statements to conform these statements to actual results, except as required by applicable law, including the securities laws of the United States.

AVAILABLE INFORMATION

Hydrocarb Energy Corp. files annual, quarterly and current reports, proxy statements, and other information with the Securities and Exchange Commission (the “SEC”). You may read and copy documents referred to in this Annual Report on Form 10-K/A that have been filed with the SEC at the SEC’s Public Reference Room, 450 Fifth Street, N.W., Washington, D.C. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You can also obtain copies of our SEC filings by going to the SEC’s website at http://www.sec.gov.

REFERENCES

As used in this annual report: (i) the terms “we”, “us”, “our”, “HEC”, “Hydrocarb” and the “Company” mean Hydrocarb Energy Corp.; (ii) “SEC” refers to the Securities and Exchange Commission; (iii) “Securities Act” refers to the United States Securities Act of 1933, as amended; (iv) “Exchange Act” refers to the United States Securities Exchange Act of 1934, as amended; and (v) all dollar amounts refer to United States dollars unless otherwise indicated.

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TABLE OF CONTENTS

PART I
ITEM 1.	BUSINESS	4
ITEM 1A.	RISK FACTORS	14
ITEM 1B.	UNRESOLVED STAFF COMMENTS	30
ITEM 2.	PROPERTIES	30
ITEM 3.	LEGAL PROCEEDINGS	30
ITEM 4.	MINE SAFETY DISCLOSURES	30
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY; RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	31
ITEM 6.	SELECTED FINANCIAL DATA	33
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS	33
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA	42
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	80
ITEM 9A.	CONTROLS AND PROCEDURES	80
ITEM 9B.	OTHER INFORMATION	80
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	81
ITEM 11.	EXECUTIVE COMPENSATION	85
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	89
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	90
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	93
PART IV
ITEM 15.	EXHIBITS	95

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ITEM 1.  BUSINESS

Corporate History and Organization

We are Hydrocarb Energy Corporation, incorporated in the state of Nevada.  We have 333,333,334 common stock shares authorized and 10,000 series A preferred stock shares authorized.   While working towards plans and expectations of being listed on a major stock exchange, we currently trade on the OTCBB under the stock symbol “HECC”.

Historically we were incorporated under the laws of the State of Nevada on April 12, 2005 under the name “Carlin Gold Corporation”. On July 19, 2005, we changed our name to “Nevada Gold Corp.” On October 18, 2005, we changed our name to “Gulf States Energy, Inc.” and increased our authorized capital from 100,000,000 shares of common stock to 500,000,000 shares of common stock, par value $0.001 per share. On September 5, 2006, we changed our name to “Strategic American Oil Corporation”.  On April 4, 2012 we completed a one for twenty-five (1:25) reverse stock split and as a result our authorized capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock.  Also, effective April 4, 2012, we changed our name to “Duma Energy Corp.”  Effective May 16, 2012, we increased our authorized capital from 20,000,000 shares to 500,000,000 shares of common stock.  Effective November 29, 2013, we increased the number of our authorized shares from 500,000,000 to 1,000,000,000 shares of common stock.  Effective February 18, 2014, we changed our name from Duma Energy Corp. to Hydrocarb Energy Corp.  Effective on May 8, 2014, we affected a 1:3 reverse split of our authorized common stock and a corresponding 1:3 reverse split of our outstanding common stock setting our authorized shares of common stock to 333,333,334 as of the date of this filing.

We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas limited liability company, (iii) SPE Navigation I, LLC, a Nevada limited liability company, (iv) Namibia Exploration, Inc., a Nevada corporation, (v) Hydrocarb Corporation, a Nevada corporation, (vi) Hydrocarb Texas Corporation, a Texas corporation, and (vii) Hydrocarb Namibia Energy (Pty) Limited, a company chartered in the Republic of Namibia.  In addition, we own 95% of the issued and outstanding share capital of Otaiba Hydrocarb LLC, a UAE limited liability corporation.

Our principal offices are located at 800 Gessner, Suite 375, Houston, Texas, 77024. Our telephone number is (713) 970-1590 and our fax number is (713) 970-1591.  We maintain a website at http://www.hydrocarb.com. Information on our web site is not part of this filing, and we do not desire to incorporate by reference such information herein.

General

Our corporate mission statement is:

To realize extraordinary shareholder value as a frontier exploration and production company that continually enhances its domestic reserves and production while internationally achieving new world class petroleum discoveries.

We are a natural resource exploration and production company engaged in the exploration, acquisition, development, and production of oil and gas properties in the United States and onshore in Namibia, Africa.  As of July 31, 2014, we maintain developed acreage offshore in Texas.  As of July 31, 2014, we were producing oil and gas from our working interest in  Galveston Bay, Texas.  During September 2012, we acquired, through the acquisition of Namibia Exploration Inc., a 39% non-operated working interest in a concession located onshore in Namibia, Africa.  During December 2013, with our acquisition of Hydrocarb Corporation, we acquired a 51% working interest in this onshore Namibia, Africa concession and now own a 90% working interest (100% cost responsibility) in this concession.

As part of our ongoing business strategy, we continue to review and evaluate acquisition opportunities in the continental United States and internationally.

Exploration and Production Activities

Our oil and gas interests as of July 31, 2014 were as follows:

Producing properties

Galveston Bay, Texas

Through our subsidiary, Galveston Bay Energy, LLC (“GBE”), we hold majority interests (approximately 93% working interest) and operate four fields in the shallow waters of Galveston Bay which is Southeast of Houston, Texas. Currently, we are producing the four fields that were acquired with GBE. The fields were shut-in in September 2008 due to a direct hit from Hurricane Ike. The then-owner went into bankruptcy and the properties were purchased out of bankruptcy by a private seller who performed reconstruction work on the fields and later sold them to us.

4

Unproved property – Namibia

Through our subsidiaries, Namibia Exploration, Inc. (“NEI”) and Hydrocarb Namibia Energy (Pty) Limited (“Hydrocarb Namibia”) we hold the rights to a 90% working interest (100% cost responsibility) in an onshore petroleum concession (the “Concession”), located in the Republic of Namibia, measuring approximately 5.3 million acres and covered by Petroleum Exploration License No. 0038 as issued by the Republic of Namibia Ministry of Mines and Energy. We hold our working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. (“NPC Namibia”).

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 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.

As of July 31, 2014, approximately $2.1 million has been expended towards the initial exploration period.

Going forward, we plan to continue our exploration work with a 2D seismic program.  We plan to continue working toward entering the first extension of our exploration period.  With our first exploration extension as provided for in our Petroleum Agreement, we would work to begin drilling exploration wells that have the potential to yield a major discovery.

5

Oil and Gas Reserves

The following table illustrates and provides a summary of our oil and gas reserves as of our fiscal year ended July 31, 2014, as estimated by third party reservoir engineers.

Summary of Oil and Gas Reserves as of July 31, 2014 Based on Average Fiscal-Year Prices

Reserves Category	Oil (Mbls)		Natural Gas (MMcf)		Equivalent (MMcfe)
PROVED:
Developed		413.3		5,783.2		8,262.9
Undeveloped		608.5		6,248.2		9,899.1
Total Proved		1021.8		12,031.4		18,162.0

Our estimates of proved reserves, located in Texas, USA, disclosed in this Form 10-K, at July 31, 2014 and 2013 were prepared by Ralph E. Davis Associates, Inc. (“RED”), our independent consulting petroleum engineers. The technical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

The reserves in this report have been estimated using deterministic methods. For wells classified as proved developed where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. Although the SEC’s reserves rules allow probable and possible reserves to be disclosed separately, we have elected not to disclose probable and possible reserves in this report.

In Texas, the Company’s proved undeveloped reserves are located on acreage held by production. Total acreage on these leases is 18,376, of this number, 1,040 acres are currently proved, developed, producing acres, and 17,336 acres are considered undeveloped.  The Company has reported proved undeveloped reserves as a result of existing wells which require major expenditures to develop the reserves.

Internal Controls Over Reserves Estimates

Our policies regarding internal controls over the recording of reserves estimates require reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Our internal controls over reserve estimates also include the following:

·Utilization of an independent consulting petroleum engineer for the preparation of reserves estimates for 100% of our reserves and

·Involvement of personnel with appropriate background and experience to oversee the reserves estimate process and provide the requested data to the independent petroleum engineer.

Our Vice President, Craig Alexander, is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Mr. Alexander has a Bachelor of Science degree in Petroleum Engineering and over 23 years of industry experience with positions of increasing responsibility in production and completion engineering and operations management. Mr. Alexander reports directly to our President.

Technologies Used in Reserves Estimation

The SEC allows the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty in connection with the establishment of reserves.  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.

We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserves estimates.

RED used the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance. In the conduct of the reserve study, RED did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the reserve study something came to the attention of RED which brought into question the validity or sufficiency of any such information or data, RED did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.  RED did not perform a personal field inspection of our properties.

6

Changes in Proved Undeveloped Reserves

As of July 31, 2014, we reported 9,899.1 MMcfe of proved undeveloped reserves, which represents an increase of 2,679.3 MMcfe from July 31, 2013.  The following table shows of the changes in total proved undeveloped reserves for 2014:

Beginning of year	7,219.7
Revision of previous estimate	2,679.3
End of year	9,899.0

Before our acquisition of GBE during the year ended July 31, 2011, we had no proved undeveloped reserves.  Accordingly, we have no proved undeveloped reserves that have been undeveloped for five years since their original disclosure as proved undeveloped reserves.

During the year ended July 31, 2014, the Company has concentrated on infrastructure, indentifying potential workover and recompletions, and obtaining financing to complete this work.  The increase in proved undeveloped reserves was a result of an increase in certain previously estimated oil reserves in the Galveston Bay, Texas property. When we acquired Galveston Bay Energy LLC in 2011, the Company had over 100 well-bores that had been shut in and scheduled for potential plugging and abandonment. Since the date of the acquisition, our technical staff undertook a review of the old well logs and other technical data to identify additional undeveloped oil reserves in these leases. All increases in proved undeveloped reserves are due to the re-evaluation of previously available technical data associated with such review. We have not obtained new technical data. We believe that the new interpretations and reevaluations better reflect the underlying technical data. For the year ended July 31, 2014, this increase related primarily to revaluations associated with the Trinity Bay Field.
 

Production and Price History

The tables below sets forth the net quantities of oil and gas production, net of royalties, attributable to us in the years ended July 31, 2014 and 2013. For the purposes of this table, the following terms have the following meanings: (i) “Bbl” means one stock tank barrel or 42 U.S. gallons liquid volume; (ii) “Mcf” means one thousand cubic feet; (iii) “Mcfe” means one thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil; and (iv) “MMcf” means one million cubic feet.

Property	2014		2013
Oil (Bbls):
Galveston Bay, Texas		40,536		57,796
The Welder Lease (Barge Canal), Calhoun Co. Texas		1,900		3,488
Markham City, Cook Co., Illinois		-		151
Chapman Ranch II Prospect, Nueces, Co., Texas		-		36
Karnes Co., Texas		-		4
Total Oil		42,436		61,475

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Property	2014		2013
Gas (Mcf)
Galveston Bay, Texas		110,286		75,164
The Welder Lease (Barge Canal), Calhoun Co. Texas		63,135		100,116
Palacios Prospect, Duval Co., Texas		148		1,113
Karnes Co., Texas		-		323
Total Gas		173,569		176,716

Property	2014		2013
Total (Mcfe)
Galveston Bay, Texas		353,502		421,940
The Welder Lease (Barge Canal), Calhoun Co. Texas		74,535		121,044
Palacios Prospect, Duval Co., Texas		148		1,113
Markham City, Cook Co., Illinois		-		906
Chapman Ranch II Prospect, Nueces Co., Texas		-		216
Karnes Co., Texas		-		347
Total Mcfe		428,185		545,566
Average Prices:
Oil (per Bbl)	$	102.87	$	105.63
Gas (per Mcf)	$	4.03	$	3.40
Total (per Mcfe)	$	11.83	$	12.99
Average Costs (per Mcfe):
Lease operating expense (per Mcfe) (1)	$	11.47	$	8.28

(1) Taxes, transportation and production-related administrative expenditures are included in lease operating expenses.

Net production includes only production that is owned by us, whether directly or beneficially, and produced to our interest, less royalties and production due to others. Production of natural gas includes only marketable production of gas on an “as sold” basis. Production of natural gas includes only dry, residue and wet gas, depending on whether liquids have been extracted before we passed title, and does not include flared gas, injected gas and gas consumed in operations. Recovered gas, lift gas and reproduced gas are not included until sold.

Drilling and Other Exploratory Development Activities

The following tables set forth information regarding (i) the number of net productive and dry exploratory wells drilled and (ii)  the number of net productive and dry development wells drilled during the years indicated, expressed separately for oil and gas. For the purposes of this subsection:

·A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

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·A productive well is an exploratory, development, or extension well that is not a dry well.

·Completion refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

·The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated.  A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.

For the purposes of this subsection (i) one or more completions in the same bore hole have been counted as one well, and (ii) a well with one or multiple completions at least one of which is an oil completion has been classified as an oil well. We do not have any wells with multiple completions.

Number of Wells Drilled During Year Ended July 31, 2014

Net Productive Exploratory Wells

Net Dry Exploratory Wells

Net Productive Development Wells

Net Dry Development Wells

Net Productive Exploratory Wells

Net Dry Exploratory Wells

Net Productive Development Wells

Net Dry Development Wells

Illinois

-

-

-

-

-

-

-

-

Texas

-

-

-

-

-

-

-

-

Total

-

-

-

-

-

-

-

-

Number of Wells Drilled During Year Ended July 31, 2013

	Net Productive Exploratory Wells		Net Dry Exploratory Wells		Net Productive Development Wells		Net Dry Development Wells		Net Productive Exploratory Wells		Net Dry Exploratory Wells		Net Productive Development Wells		Net Dry Development Wells
Illinois		-		-		-		-		-		-		-		-
Texas		-		1.00		-		0.25		-		-		-		-
Total		-		1.00		-		0.25		-		-		-		-

Present Activities

We own a 25% non-operated interest in a well that was drilled onshore in Nueces County, Texas beginning in June 2012.  The well was originally completed to a non-economic zone.  We conducted a series of recompletions and reworks during the year ended July 31, 2013.  The operations were not successful, and the well was plugged and abandoned during the year ended July 31, 2014. 

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Delivery Commitments

None.

Productive Wells

The following table sets forth information regarding the total gross and net productive wells as of July 31, 2014, expressed separately for oil and gas. All of our productive oil and gas wells were located in Texas. For the purposes of this subsection: (i) one or more completions in the same bore hole have been counted as one well, and (ii) a well with one or multiple completions at least one of which is an oil completion has been classified as an oil well. We do not have any wells with multiple completions.

Number of Operating Wells

	Oil				Gas
	Gross		Net		Gross		Net
Texas		22.00		20.81		9.00		8.32

A productive well is an exploratory well, development well, producing well or well capable of production, but does not include a dry well. A dry well, or a dry hole, is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

A gross well is a well in which a working interest is owned, and a net well is the result obtained when the sum of fractional ownership working interests in gross wells equals one. The number of gross wells is the total number of wells in which a working interest is owned, and the number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. The “completion” of a well means the installation of permanent equipment for the production of oil or gas, or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency.

Acreage

The following table sets forth information regarding our gross and net developed and undeveloped oil and natural gas acreage under lease as of July 31, 2014.

	Gross (1)		Net
Developed Acreage
Texas, USA		1,040		1,029
Undeveloped Acreage
Texas, USA		17,336		17,145
Namibia, Africa		5,300,000		4,770,000
Total		5,318,376		4,788,174

(1) The gross acreage cited includes leasehold acreage to be earned under the farm-out agreements.

Namibia, Africa

In September 2012, we acquired a 39% working interest in a concession in Namibia, Africa.  With our acquisition of HCN in December 2013, we acquired an additional 51% working interest and we now own a working interest of 90% of this concession.  This property is a 5.3 million-acre concession in northern Namibia in Africa.

In Texas, the Company’s proved undeveloped reserves are located on acreage held by production. Total acreage on these leases is 18,376, of this number, 1,040 acres are currently proved, developed, producing acres, and 17,336 acres are considered undeveloped.  The Company has reported proved undeveloped reserves as a result of existing wells which require major expenditures to develop the reserves.

A developed acre is an acre spaced or assignable to productive wells, a gross acre is an acre in which a working interest is owned, and a net acre is the result that is obtained when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not such acreage contains proved reserves. As is customary in the oil and gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the lease or by payment of delay rentals during the remaining primary term of the lease. The oil and natural gas leases in which we have an interest are for varying primary terms.  Most of our developed lease acreage is beyond the primary term and is held so long as oil or natural gas is produced in commercial quantities or operations are commenced to restore production as our leases terms expire when the Company ceases drilling activity.

Most of our developed lease acreage is held by production and is beyond the primary lease term.  As such, the Company’s leases related to the Texas properties are held so long as oil or natural gas is produced in commercial quantities or operations are commenced to restore production with our lease terms expiring only when the Company ceases drilling activity.

The lease terms related to the Company’s working interest in the Namibia concession has an “Initial Exploration Period” which expires September 2015 with a minimum expenditure requirement of $4,505,000.  Subsequent to the Initial Exploration Period the Company has a “First Renewal Exploration Period” of two years from end of the Initial Exploration Period.  During the First Renewal Period the Company must relinquish 25% of the exploration license area and has a minimum expenditure of $17,350,000.  Subsequent to the First Renewal Period the Company has a “Second Renewal (Production License) Exploration Period” of 25 years and has a minimum expenditure of $300,000.

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Plan of Operations

Our Plan of Operations is described in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Government Regulation

General

The availability of a ready market for oil and gas production depends upon numerous factors beyond our control. These factors include local, state, federal and international regulation of oil and gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and gas available for sale, the availability of adequate pipeline and other transportation and processing facilities, and the marketing of competitive fuels. State and federal regulations are generally intended to prevent waste of oil and gas, protect rights to produce oil and gas between owners in a common reservoir, and control contamination of the environment.

Applicable legislation is under constant review for amendment or expansion. These efforts frequently result in an increase in the regulatory burden on companies in our industry and as a consequence an increase in the cost of doing business and decrease in profitability. Numerous federal and state departments and agencies issue rules and regulations imposing additional burdens on the oil and gas industry that are often costly to comply with and carry substantial penalties for non-compliance. Our production operations may be affected by changing tax and other laws relating to the petroleum industry, constantly changing administrative regulations and possible interruptions or termination by government authorities.

The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government and are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission (FERC) is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. Some recent FERC proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.

State regulatory authorities have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning operations. Many states have statutes and regulations governing various environmental and conservation matters, including the establishment of maximum rates of production from oil and gas wells, and restricting production to the market demand for oil and gas. Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced. Most states impose a production or severance tax with respect to the production and sale of crude oil, natural gas and natural gas liquids within their respective jurisdictions. State production taxes are generally applied as a percentage of production or sales.

Oil and gas rights may be held by individuals and corporations, and, in certain circumstances, by governments having jurisdiction over the area in which such rights are located. As a general rule, parties holding such rights grant licenses or leases to third parties, such as us, to facilitate the exploration and development of these rights. The terms of the licenses and leases are generally established to require timely development. Notwithstanding the ownership of oil and gas rights, the government of the jurisdiction in which the rights are located generally retains authority over the manner of development of those rights.

U.S. Federal and State Taxation

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has recently proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies such as us. President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible U.S. drilling costs as incurred and percentage depletion. Many states have raised state taxes on energy sources, and additional increases may occur. Changes to tax laws could adversely affect our business and our financial results.

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Environmental

General.  Our activities are subject to local, state and federal laws and regulations governing environmental quality and pollution control in the United States. The exploration, drilling and production from wells, natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing natural gas and other products, are subject to stringent environmental laws and regulations by state and federal authorities, including the Environmental Protection Agency (“EPA”). These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands and other ecologically sensitive and protected areas, and impose substantial remedial liabilities for pollution resulting from drilling operations. Such regulation can increase our cost of planning, designing, installing and operating such facilities.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of significant investigatory or remedial obligations, and the imposition of injunctive relief that limits or prohibits our operations. Moreover, some environmental laws provide for joint and several strict liability for remediation of releases of hazardous substances, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances, such as oil and gas related products.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current environmental laws and regulations and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.

Waste Disposal.  We currently lease, and intend in the future to own or lease, additional properties that have been used for production of oil and gas for many years. Although we and our operators utilize operating and disposal practices that are standard in the industry, previous owners or lessees may have disposed of or released hydrocarbons or other wastes on or under the properties that we currently own or lease or properties that we may in the future own or lease. In addition, many of these properties have been operated in the past by third parties over whom we had no control as to such entities’ treatment of hydrocarbons or other wastes or the manner in which such substances may have been disposed of or released. State and federal laws applicable to oil and gas wastes and properties may require us to remediate property, including ground water, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

We may generate wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA has limited the disposal options for certain wastes that are designated as hazardous under RCRA. Furthermore, it is possible that certain wastes generated by our oil and gas projects that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly operating and disposal requirements.

CERCLA.  The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons or so-called potentially responsible parties include the current and certain past owners and operators of a facility where there is or has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of the hazardous substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally exempts petroleum from the definition of hazardous substances, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may in the future be an owner of facilities on which hazardous substances have been released by previous owners or operators of our properties that are named as potentially responsible parties related to their ownership or operation of such property.

Air Emissions.  Our projects are subject to local, state and federal regulations for the control of emissions of air pollution. Major sources of air pollutants are subject to more stringent, federally imposed permitting requirements, including additional permits. Producing wells, gas plants and electric generating facilities generate volatile organic compounds and nitrogen oxides. Some of our producing wells may be in counties that are designated as non-attainment for ozone and may be subject to restrictive emission limitations and permitting requirements. If the ozone problems in the applicable states are not resolved by the deadlines imposed by the federal Clean Air Act, or on schedule to meet the standards, even more restrictive requirements may be imposed, including financial penalties based upon the quantity of ozone producing emissions. If we fail to comply strictly with air pollution regulations or permits, we may be subject to monetary fines and be required to correct any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air emission sources.

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Clean Water Act.  The Clean Water Act imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. Permits must be obtained to discharge pollutants into federal waters. The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require us to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs.

Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act, and similar legislation enacted in Texas, Louisiana and other coastal states, impose certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in United States waters and adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility or vessel that is a source of an oil discharge or poses the substantial threat of discharge, or the lessee or permittee of the area in which a facility covered by OPA is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs, remediation of environmental damage and a variety of public and private damages. OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs of a potential spill. Few defenses exist to the liability imposed by OPA. In the event of an oil discharge, or substantial threat of discharge from our properties, vessels and pipelines, we may be liable for costs and damages.  There is soil contamination at a tank facility owned by GBE. Depending on the technique used to perform the remediation, we estimate the cost range to be between $150,000 and $900,000. We cannot determine a most likely scenario, thus we have recognized the lower end of the range. We have submitted a remediation plan to the appropriate authorities and have not yet received a response. For the year ended July 31, 2014 and July 31, 2013, $150,000 has been recognized and is included in the balance sheet caption “Accounts payable and accrued expenses.”

Other than as noted above, we believe that we are in substantial compliance with current environmental laws and regulations in each of the jurisdictions in which we operate and there are no other significant liabilities or uncertainties. Although we have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.

Insurance

Our oil and gas properties are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, implosions, fires and oil spills. These conditions can cause:

· Damage to or destruction of property, equipment and the environment;

· Personal injury or loss of life; and

· Suspension of operations.

We maintain insurance coverage that we believe to be customary in the industry against these types of hazards. However, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination. The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations.

Competition

The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. We are a minor participant in the industry and compete in the oil and natural gas industry with many other companies having far greater financial, technical and other resources.

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We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs.

Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. Many of our competitors have a longer history of operations than we have, and most of them have also demonstrated the ability to operate through industry cycles.

Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States and other countries, as well as factors that we cannot control, including international political conditions, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources. Intense competition occurs with respect to marketing, particularly of natural gas.

Employees

We currently have 12 full-time employees and no part-time employees.

Subsidiaries

We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas limited liability company, (iii) SPE Navigation I, LLC, a Nevada limited liability company, (iv) Namibia Exploration, Inc., a Nevada corporation, (v) Hydrocarb Corporation, a Nevada corporation, (vi) Hydrocarb Texas Corporation, a Texas corporation, and (vii) Hydrocarb Namibia Energy (Pty) Limited, a company chartered in the Republic of Namibia.  In addition, we own 95% of the issued and outstanding share capital of Otaiba Hydrocarb LLC, a UAE limited liability corporation.

ITEM 1A. RISK FACTORS

An investment in our common stock involves a number of very significant risks. You should carefully consider the following risks and uncertainties in addition to other information in this annual report in evaluating our company and its business before purchasing shares of our common stock. Our business, operating results and financial condition could be seriously harmed due to any of the following risks. The risks described below may not be all of the risks facing our company. Additional risks not presently known to us or that we currently consider immaterial may also impair our business operations. You could lose all or part of your investment due to any of these risks.

Risks Related to Our Company

Because we have only recently commenced business operations, we face a high risk of business failure.

We were incorporated on April 12, 2005 and originally planned to explore for gold and other minerals, but we soon shifted our focus to oil and gas exploration. Revenues were limited until our acquisition of GBE in 2011 and to date, we have not achieved profitability. Potential investors should be aware of the difficulties normally encountered by companies in the early stages of their life cycle and the high rate of failure of such enterprises. These potential problems include, but are not limited to, unanticipated problems relating to costs and expenses that may exceed current estimates. We have no actual company history upon which to base any assumption as to the likelihood that our business will prove successful, and it is possible, although not anticipated, that we may never achieve profitable operations.

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We will need additional capital to complete future acquisitions, conduct our operations and fund our business and our ability to obtain the necessary funding is uncertain.

We will need to raise additional funding to complete future potential acquisitions and may need to raise additional funds through public or private debt or equity financing or other various means to fund our operations, acquire assets and complete exploration and drilling operations. In such a case, adequate funds may not be available when needed or may not be available on favorable terms. If we need to raise additional funds in the future, by issuing equity securities, dilution to existing stockholders will result, and such securities may have rights, preferences and privileges senior to those of our common stock. If funding is insufficient at any time in the future and we are unable to generate sufficient revenue from new business arrangements, to complete planned acquisitions or operations, our results of operations and the value of our securities could be adversely affected.

We have substantial indebtedness which could adversely affect our financial flexibility and our competitive position.

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 lenders party thereto (the “Lenders”).  Pursuant to the Credit Agreement, the Lenders loaned us $4 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%.  Pursuant to the Credit Agreement, we have the right, at any time prior to the one year anniversary of the Credit Agreement, to borrow up to an additional $1,000,000 under the Credit Agreement (the “Additional Loan”), subject to certain pre-requisites and requirements as set forth in the Credit Agreement, including, but not limited to us raising $750,000 through the sale of equity subsequent to the closing of the transactions contemplated by the Credit Agreement (which we agreed to obtain within 150 days of the date of the Credit Agreement).  The proceeds of the Additional Loan may only be used for the Oil and Gas Activities.

The amount owed pursuant to the Notes (and any amount borrowed pursuant to the Additional Loan) is guaranteed by our wholly-owned subsidiary, Hydrocarb Corporation (“HC”) and its subsidiaries, and our other wholly-owned subsidiaries and is secured by a first priority security interest in substantially all of our assets (including, but not limited to the securities of our subsidiaries and HC and its subsidiaries) evidenced by a Guarantee and Collateral Agreement, various pledge agreements and a deed of trust providing the Agent, as agent for the Lenders, a security interest over our oil and gas assets and rights.

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.

The Credit Agreement includes customary events of default for facilities of a similar nature and size as the Credit Agreement, including, but not limited to, if any breach or default occurs under the Loan Documents, the failure of the Company to pay any amount when due under the Loan Documents, if the Company (or its subsidiaries) is subject to any judgment in excess of $250,000 which is not discharged or stayed within 30 days, or if a change in control of the Company, any subsidiary or any guarantor should occur, defined for purposes of the Credit Agreement as any transfer of 25% or more of the voting stock of such entity.

Our substantial indebtedness could have important consequences and significant effects on our business. For example, it could:

· increase our vulnerability to adverse changes in general economic, industry and competitive conditions;

· require us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate purposes;

· limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

· restrict us from taking advantage of business opportunities;

· make it more difficult to satisfy our financial obligations;

· place us at a competitive disadvantage compared to our competitors that have less debt obligations; and

· limit our ability to borrow additional funds for working capital, capital expenditures, acquisitions, debt service requirements, execution of our business strategy or other general corporate purposes on satisfactory terms or at all.

We may need to raise additional funding in the future to repay or refinance the Notes and our accounts payable, and as such may need to seek additional debt or equity financing. Such additional financing may not be available on favorable terms, if at all. If debt financing is available and obtained, our interest expense may increase and we may be subject to the risk of default, depending on the terms of such financing. If equity financing is available and obtained it may result in our shareholders experiencing significant dilution. If such financing is unavailable, we may be forced to curtail our operations, which may cause the value of our securities to decline in value and/or become worthless.

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The repayment of our Credit Agreement is secured by a security interest in all of our assets.

The repayment of the Notes represented pursuant to the Credit Facility is guaranteed by our wholly-owned subsidiary, Hydrocarb Corporation (“HC”) and its subsidiaries, and our other wholly-owned subsidiaries and is secured by a first priority security interest in substantially all of our assets (including, but not limited to the securities of our subsidiaries and HC and its subsidiaries) evidenced by a Guarantee and Collateral Agreement, various pledge agreements and a deed of trust providing the Agent, as agent for the Lenders, a security interest over our oil and gas assets and rights. If we default in the repayment of the Notes or the Credit Agreement and/or any of the terms and conditions thereof, the Lenders may enforce their security interest over our assets which secure the repayment of such debt, and we could be forced to curtail or abandon our current business plans and operations. If that were to happen, any investment in the Company could become worthless.

We may not be able to effectively manage the demands required of a new business in our industry, such that we may be unable to successfully implement our business plan or achieve profitability.

We have earned limited revenues until recently (the past three years) and we have never achieved annual profitability. We may not be able to effectively execute our business plan or manage any growth, if any, of our business. Future development and operating results will depend on many factors, including access to adequate capital, the demand for oil and gas, price competition, and whether we can control costs. Many of these factors are beyond our control. In addition, our future prospects must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a new business in the oil and gas industry, which is characterized by intense competition, rapid technological change, highly litigious competitors and significant regulation. If we are unable to address these matters, or any of them, then we may not be able to successfully implement our business plan or achieve profitability.

Because we have earned limited revenues from operations, most of our capital requirements have been met through financing and we may not be able to continue to find financing to meet our operating requirements.

We may need to obtain additional financing in order to pursue our business plan. As of July 31, 2014, we had cash and cash equivalents of $144,258 and a working capital deficit of $3,566,332. As such, unless our cash flow from operations is sufficient, we will need additional financing to pursue the exploration and development of our properties and pay for corporate overhead.  We may not be able to obtain such financing at all or in amounts that would be sufficient for us to meet our current and expected working capital needs. Furthermore, in the event that our plans change or our assumptions change or prove inaccurate, we could be required to seek additional financing in greater amounts than is currently anticipated. Any inability to obtain additional financing when needed would have a material adverse effect on us, including possibly requiring us to significantly curtail or possibly cease our operations. In addition, any future equity financing may involve substantial dilution to our existing stockholders.

Because we have a history of losses and anticipate continued losses unless and until we are able to generate sufficient revenues to support our operations, we may lack the financial stability required to continue operations.

Since inception we have suffered recurring losses. We have funded our operations largely through the issuance of common stock in order to meet our strategic objectives. Our current level of oil and gas production is not sufficient to completely fund our exploration and development budget, such that we anticipate that we may need additional financing in order to pursue our plan of operations. We anticipate that our losses will continue until such time, if ever, as we are able to generate sufficient revenues to support our operations.

Costs of drilling, completing and operating wells is uncertain, and we may not achieve sufficient production to cover such costs.

The cost of drilling, completing and operating wells is often uncertain. We may not be able to achieve commercial production of oil and gas to pay such costs. Drilling operations on our properties or on properties we may acquire in the future may be curtailed, delayed or cancelled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit or a recovery of drilling, completion and operating costs. As a result, our business, results of operations and financial condition may be materially adversely affected.

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Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, which could have a material adverse effect on our business, results of operations and financial condition.

There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond the control of the producer. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from prepared by different engineers or by the same engineers but at different times may vary substantially, and such reserve estimates may be subject to downward or upward adjustment based upon such factors. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, when and if made, and such variances may be material, which could have a material adverse effect on our business, results of operations and financial condition.

Our future oil and natural gas production is highly dependent upon our ability to find or acquire reserves.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves, if any, will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring reserves in the future. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. The failure of an operator of our wells to adequately perform operations, or such operator’s breach of the applicable agreements, could adversely impact us. In addition, we may not obtain additional proved reserves or be able to drill productive wells at acceptable costs, in which case our business would fail.

Oil and gas resources may contain certain hazards which may, in turn, create certain liabilities or prevent the resources from being commercially viable.

Our properties may contain hazards such as unusual or unexpected formations and other conditions. Our projects may become subject to liability for pollution, fire, explosion, blowouts, cratering and oil spills, against which we cannot insure or against which we may decide to not insure. Such events could result in substantial damage to oil and gas wells, producing facilities and other property and/or result in personal injury. Costs or liabilities related to those events would have a material adverse effect on our business, results of operations, financial condition and cash flows.

Our success is dependent on the prices of oil and natural gas.  Low oil or natural gas prices and the substantial volatility in these prices may adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure requirements and financial obligations.

The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the prices for oil and natural gas have been volatile and will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include the following:

· the domestic and foreign supply of oil and natural gas;

· the domestic and foreign demand for oil and natural gas;

· the prices and availability of competitors’ supplies of oil and natural gas;

· the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls;

· the price and quantity of foreign imports of oil and natural gas; and

· the impact of U.S. dollar exchange rates on oil and natural gas prices;

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· domestic and foreign governmental regulations and taxes;

· speculative trading of oil and natural gas futures contracts;

· localized supply and demand fundamentals, including the availability, proximity and capacity of gathering and transportation systems for natural gas;

· the availability of refining capacity;

· the prices and availability of alternative fuel sources;

· weather conditions and natural disasters;

· political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America;

· the continued threat of terrorism and the impact of military action and civil unrest;

· public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;

· the level of global oil and natural gas inventories and exploration and production activity;

· authorization of exports from the Unites States of liquefied natural gas;

· the impact of energy conservation efforts;

· technological advances affecting energy consumption; and

· overall worldwide economic conditions.

Declines in oil or natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that we can produce economically. Should natural gas or oil prices decrease from current levels and remain there for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, and, as a result, we may have to make substantial downward adjustments to our estimated proved reserves, each of which would have a material adverse effect on our business, financial condition and results of operations.

Our exploration, development and exploitation projects require substantial capital expenditures that may exceed cash on hand, cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth.

Our exploration and development activities are capital intensive.  We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves.  Our cash on hand, our operating cash flows and future potential borrowings may not be adequate to fund our future acquisitions or future capital expenditure requirements.  The rate of our future growth may be dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.

Our cash flows from operations and access to capital are subject to a number of variables, including:

· our estimated proved oil and natural gas reserves;

· the amount of oil and natural gas we produce from existing wells;

· the prices at which we sell our production;

· the costs of developing and producing our oil and natural gas reserves;

· our ability to acquire, locate and produce new reserves;

· the ability and willingness of banks to lend to us; and

· our ability to access the equity and debt capital markets.

In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies.  Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.

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If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in additional exploration opportunities.  Alternatively, a significant improvement in oil and natural gas prices or other factors could result in an increase in our capital expenditures and we may be required to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or farm out of interests in our assets, the borrowing of funds or otherwise to meet any increase in capital needs.  If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected.  Further, future debt financings may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions.  Debt financing may involve covenants that restrict our business activities. If we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we choose to farm-out interests in our prospects, we may lose operating control over such prospects.

Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will receive, and significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating accumulations of oil and natural gas is complex and is not exact, due to numerous inherent uncertainties.  The process relies on interpretations of available geological, geophysical, engineering and production data.  The extent, quality and reliability of this technical data can vary.  The process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  The accuracy of a reserves estimate is a function of:

· the quality and quantity of available data;

· the interpretation of that data;

· the judgment of the persons preparing the estimate; and

· the accuracy of the assumptions.

The accuracy of any estimates of proved reserves generally increases with the length of the production history.  Due to the limited production history of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.  As our wells produce over time and more data is available, the estimated proved reserves will be re-determined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates.  It is possible that future production declines in our wells may be greater than we have estimated.  Any significant variance to our estimates could materially affect the quantities and present value of our reserves.

We may have accidents, equipment failures or mechanical problems while drilling or completing wells or in production activities, which could adversely affect our business.

While we are drilling and completing wells or involved in production activities, we may have accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans.  We may also damage a potentially hydrocarbon-bearing formation during drilling and completion operations.  Such incidents may result in a reduction of our production and reserves from the well or in abandonment of the well.

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Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including:

· unusual or unexpected geologic formations;

· natural disasters;

· adverse weather conditions;

· unanticipated pressures;

· loss of drilling fluid circulation;

· blowouts where oil or natural gas flows uncontrolled at a wellhead;

· cratering or collapse of the formation;

· pipe or cement leaks, failures or casing collapses;

· fires or explosions;

· releases of hazardous substances or other waste materials that cause environmental damage;

· pressures or irregularities in formations; and

· equipment failures or accidents.

In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices.

Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses.  The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.  Insurance against all operational risks is not available to us.  We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable.   Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.  Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms.  Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future.  As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles.  Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.

The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our business, financial condition and results of operations.

Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnel could delay or adversely affect our operations.  When drilling activity in the United States and elsewhere increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry.  These costs may increase, and necessary equipment and services may become unavailable to us at economical prices.  Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition and results of operations.

In addition, the demand for hydraulic fracturing services currently exceeds the availability of fracturing equipment and crews across the industry and in our operating areas in particular.  The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages has further amplified this equipment and crew shortage. If demand for fracturing services continues to increase or the supply of fracturing equipment and crews decreases, then higher costs could result and could adversely affect our business, financial condition and results of operations.

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The marketability of our production is dependent upon oil and natural gas gathering and transportation facilities owned and operated by third parties, and the unavailability of satisfactory oil and natural gas transportation arrangements would have a material adverse effect on our revenue.

The unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production from our wells.  The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for, and supply of, oil and natural gas and the proximity of reserves to pipelines and terminal facilities.  Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties.  Our failure to obtain these services on acceptable terms could materially harm our business.  We may be required to shut-in wells for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity.  If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market.  Furthermore, if we were required to shut-in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.  We do not expect to purchase firm transportation capacity on third-party facilities.  Therefore, we expect the transportation of our production to be generally interruptible in nature and lower in priority to those having firm transportation arrangements.

The disruption of third-party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products.  The third parties control when or if such facilities are restored and what prices will be charged.  Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition and results of operations and our ability to execute our business plan in a timely fashion.

Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources.  As we expand our activities, including our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources.  The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers and landmen could have a material adverse effect on our business, financial condition and results of operations and our ability to execute our business plan in a timely fashion.

Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease our cash flow from operations and adversely affect the exploration and development of our prospects and assets.

We will derive substantially all of our revenues from the sale of our oil and natural gas to unaffiliated third-party purchasers, independent marketing companies and mid-stream companies.  Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations.

Liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project.  Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due.  In the case of a farm-out party, we would have to find a new farm-out party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farm-out agreement.  In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs.  We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farm-out party.

The calculated present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the present value of future net cash flows as included in our public filings is the current market value of our estimated proved oil and natural gas reserves.  We generally base the estimated discounted future net cash flows from proved reserves on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate.  Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:

· actual prices we receive for oil and natural gas;

· actual cost and timing of development and production expenditures;

· the amount and timing of actual production; and

· changes in governmental regulations or taxation.

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In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.

We may incur additional indebtedness which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs.

In the future, we may incur significant amounts of additional indebtedness in order to make acquisitions or to develop our properties.  Our level of indebtedness could affect our operations in several ways, including the following:

· a significant portion of our cash flows could be used to service our indebtedness;

· a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

· any covenants contained in the agreements governing our outstanding indebtedness could limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

· a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness may prevent us from pursuing; and

· debt covenants to which we may agree may affect our flexibility in planning for, and reacting to, changes in the economy and in our industry.

A high level of indebtedness increases the risk that we may default on our debt obligations.  We may not be able to generate sufficient cash flows to pay the principal or interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.  If we do not have sufficient funds and are otherwise unable to arrange financing, we may have to sell significant assets or have a portion of our assets foreclosed upon which could have a material adverse effect on our business, financial condition and results of operations.

Competition in the oil and natural gas industry is intense, making it difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel.  Also, there is substantial competition for capital available for investment in the oil and natural gas industry.  Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit.  In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.  The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future.  We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition and results of operations.

Our competitors may use superior technology and data resources that we may be unable to afford or that would require a costly investment by us in order to compete with them more effectively.

Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies and databases.  As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost.  In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can.  We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us.  One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected.

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If we do not hedge our exposure to reductions in oil and natural gas prices, we may be subject to significant reductions in prices.  Alternatively, we may use oil and natural gas price hedging contracts, which involve credit risk and may limit future revenues from price increases and result in significant fluctuations in our profitability.

In the event that we choose not to hedge our exposure to reductions in oil and natural gas prices by purchasing futures and by using other hedging strategies, we may be subject to significant reduction in prices which could have a material negative impact on our profitability.  Alternatively, we may elect to use hedging transactions with respect to a portion of our oil and natural gas production to achieve more predictable cash flow and to reduce our exposure to price fluctuations.  While the use of hedging transactions limits the downside risk of price declines, their use also may limit future revenues from price increases.  Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations.

Environmental and overall public scrutiny focused on the oil and gas industry is increasing.  The current trend is to increase regulations of our operations in the industry.  We are subject to federal, state, and local government regulation and liability, including complex environmental laws, which could require significant expenditures and/or adversely affect the cost, manner or feasibility of doing business.

Our exploration, development, production and marketing operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased our costs to plan, design, drill, install, operate and abandon natural gas and crude oil wells. Similar to other companies in our industry, we incur substantial operating and capital costs to comply with such laws and regulations. These compliance costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years—particularly with respect to hydraulic fracturing—and environmental organizations have opposed, with some success, certain drilling projects.

Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation or environmental matters and health and safety criteria addressing worker protection.  Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our business, financial condition and results of operations. These expenditures could include payments for:

· personal injuries;

· property damage;

· containment and cleanup of oil and other spills;

· the management and disposal of hazardous materials;

· remediation and clean-up costs; and

· other environmental damages.

We do not believe that full insurance coverage for all potential damages is available at a reasonable cost.  Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations.  Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements.  These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault.  We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts.  These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies.  In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations.

Additionally, the natural gas and crude oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability.

The BP crude oil spill in the Gulf of Mexico and generally heightened industry scrutiny has resulted and may result in new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, and conducted public meetings around the country on this issue which have been well publicized and well attended. This renewed focus could lead to additional federal, state and local laws and regulations affecting our drilling, fracturing and other operations.

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Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states. This could adversely affect the existing operations in these states and the economic viability of future drilling. Additional laws, regulations or other changes could significantly reduce our future growth, increase our costs of operations and reduce our cash flows, in addition to undermining the demand for the natural gas and crude oil we produce.

We are subject to federal, state and local taxes, and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition and results of operations.

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs.  In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals.  Many states have raised state taxes on energy sources, and additional increases may occur.  Changes to tax laws that are applicable to us could adversely affect our business and our financial results.

Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such possible changes include, but are not limited to, (a) the repeal of the percentage depletion allowance for oil and natural gas properties, (b) the elimination of current deductions for intangible drilling and development costs, (c) the elimination of the deduction for certain United States production activities, and (d) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States.  It is unclear whether any such changes will actually be enacted or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of the budget proposals or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our business, financial condition and results of operations.

The derivatives legislation adopted by Congress, and implementation of that legislation by federal agencies, could have an adverse impact on our ability to hedge risks associated with our business.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, the Dodd-Frank Act, which, among other things, sets forth the new framework for regulating certain derivative products including the commodity hedges of the type that we may elect to use, but many aspects of this law are subject to further rulemaking and will take effect over several years.  As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to enter into and maintain such commodity hedges and the terms of such hedges.  There is a possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges.  In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on derivative arrangements, which could include new margin, reporting and clearing requirements.  In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future.

If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us.  Any limitations or changes in our use of derivative arrangements could also materially affect our future ability to conduct acquisitions.

Legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, natural gas liquids and oil we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

On December 15, 2009, the EPA published its final findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes.  These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  Accordingly, the EPA has adopted regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and permitting and presumably requiring a reduction in greenhouse gas emissions from certain stationary sources.  In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010.  On November 30, 2010, the EPA released a final rule that expands its rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems.  The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations.  Further, various states have adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources.  Any such legislation could adversely affect demand for the natural gas, oil and liquids that we produce.

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Some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on our exploration and production operations.  Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship.  We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.  Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.

As a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act.  The law prohibits the harming of endangered or threatened species, provides for habitat protection, and imposes stringent penalties for noncompliance.  The final designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations, delays, or prohibitions on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

We face risks associated with our operations in Namibia.

We are subject to various risks associated with doing business in Namibia and relating to Namibia’s economic and political environment. As is typical of an emerging market, Namibia does not possess a well-developed business, legal and regulatory infrastructure that would generally exist in a more mature free market economy.   We could also face currency risks associated with operations in Namibia. Additionally, our successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or terrorism, and other local security concerns. Such concerns may require us to incur greater costs for security or to shut down operations for a period of time. Our planned operations in Namibia will also be subject to Namibia specific laws and regulations relating to areas of labor, tax, import and export requirements, anti-corruption, foreign exchange controls and cash repatriation restrictions, environmental, health, and safety, which will be different than U.S. laws and may force us to expend additional resources complying with such laws and regulations. Our failure to manage the risks associated with doing business in Namibia could have a material adverse effect upon our results of operations.

As a result of our intensely competitive industry, we may not gain enough market share to be profitable.

We compete in the sale of oil and natural gas on the basis of price and on the ability to deliver products. The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators in the United States and elsewhere. Because we are pursuing potentially large markets, our competitors include major, multinational oil and gas companies. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. We are a minor participant in the industry and compete in the oil and natural gas industry with many other companies having far greater financial, technical and other resources. If we are unable to compete successfully, we may never be able to sell enough product at a price sufficient to permit us to generate profits.

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The oil and natural gas market is heavily regulated, and existing or subsequently enacted laws or regulations could limit our production, increase compliance costs or otherwise adversely impact our operations or revenues.

We are subject to various federal, state and local laws and regulations. These laws and regulations govern safety, exploration, development, taxation and environmental matters that are related to the oil and natural gas industry. To conserve oil and natural gas supplies, regulatory agencies may impose price controls and may limit our production. Certain laws and regulations require drilling permits, govern the spacing of wells and the prevention of waste and limit the total number of wells drilled or the total allowable production from successful wells. Other laws and regulations govern the handling, storage, transportation and disposal of oil and natural gas and any by-products produced in oil and natural gas operations. These laws and regulations could materially adversely impact our operations and our revenues.

Laws and regulations that affect us may change from time to time in response to economic or political conditions. Thus, we must also consider the impact of future laws and regulations that may be passed in the jurisdictions where we operate. We anticipate that future laws and regulations related to the oil and natural gas industry will become increasingly stringent and cause us to incur substantial compliance costs.

The nature of our operations exposes us to environmental liabilities.

Our operations create the risk of environmental liabilities. We may incur liability to governments or to third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. We could potentially discharge oil or natural gas into the environment in any of the following ways:

· from a well or drilling equipment at a drill site;

· from a leak in storage tanks, pipelines or other gathering and transportation facilities;

· from damage to oil or natural gas wells resulting from accidents during normal operations; or

· from blowouts, cratering or explosions.

Environmental discharges may move through the soil to water supplies or adjoining properties, giving rise to additional liabilities. Some laws and regulations could impose liability for failure to obtain the proper permits for, to control the use of, or to notify the proper authorities of a hazardous discharge. Such liability could have a material adverse effect on our financial condition and our results of operations and could possibly cause our operations to be suspended or terminated on such property.

We may also be liable for any environmental hazards created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. Such liability would affect the costs of our acquisition of those properties. In connection with any of these environmental violations, we may also be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable.

Our success depends, to a large extent, on our ability to retain our key employees, and the loss of any of our key personnel could disrupt our business operations.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves.  Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Kent P. Watts, and our President Charles F. Dommer.  We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective.  If any of our other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected.  We do not currently maintain any insurance against the loss of any of these individuals.

We have an active board of directors that meets several times throughout the year and is intimately involved in our business and the determination of our operational strategies.  Our board of directors works closely with management to identify potential prospects, funding sources, acquisitions and areas for further development.  One of our directors has been involved with us since our inception and all of our directors have a deep understanding of our operations and culture.  If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and as a result, our operations may be adversely affected.

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Our directors may experience conflicts of interest which may detrimentally affect our profitability.

Certain directors and officers may be engaged in, or may in the future be engaged in, other business activities on their own behalf and on behalf of other companies and, as a result of these and other activities, such directors and officers may become subject to conflicts of interest, which could have a material adverse effect on our business. As of the date of the report, the Company is not aware of any conflicts of interest any of our directors have with the Company.

 We Incur Significant Costs As A Result Of Operating As A Fully Reporting Company And Our Management Is Required To Devote Substantial Time To Compliance Initiatives.

We incur significant legal, accounting and other expenses in connection with our status as a fully reporting public company. Specifically, we are required to prepare and file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). Additionally, our officers and directors and significant shareholders are required to file Form 3, 4 and 5’s and Schedule 13d/g’s with the SEC disclosing their ownership of the Company and changes in such ownership. Furthermore, the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and rules subsequently implemented by the SEC have imposed various new requirements on public companies, including requiring changes in corporate governance practices. As a result, our management and other personnel are required to devote a substantial amount of time and resources to the preparation of required filings with the SEC and SEC compliance initiatives. Moreover, these filing obligations, rules and regulations increase our legal and financial compliance costs and quarterly expenses and make some activities more time-consuming and costly than they would be if we were a private company. In addition, the Sarbanes-Oxley Act requires, among other things, that we maintain effective internal controls for financial reporting and disclosure of controls and procedures. Our testing has previously revealed deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses. The costs and expenses of compliance with SEC rules and our filing obligations with the SEC, or our identification of deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses, could materially adversely affect our results of operations or cause the market price of our stock to decline in value.

Risks Related to Our Common Stock

We currently have an illiquid and volatile market for our common stock, and the market for our common stock is and may remain illiquid and volatile in the future.

We currently have a highly sporadic, illiquid and volatile market for our common stock, which market is anticipated to remain sporadic, illiquid and volatile in the future. Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include:

· our actual or anticipated operating and financial performance and drilling locations, including reserve estimates;

· quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us;

· changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts;

· speculation in the press or investment community;

· public reaction to our press releases, announcements and filings with the SEC;

· sales of our common stock by us or other shareholders, or the perception that such sales may occur;

· the limited amount of our freely tradable common stock available in the public marketplace;

· general financial market conditions and oil and natural gas industry market conditions, including fluctuations in commodity prices;

· the realization of any of the risk factors presented in this Annual Report;

· the recruitment or departure of key personnel;

· commencement of, or involvement in, litigation;

· the prices of oil and natural gas;

· the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;

· changes in market valuations of companies similar to ours; and

· domestic and international economic, legal and regulatory factors unrelated to our performance.

Our stock price may be impacted by factors that are unrelated or disproportionate to our operating performance. The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.  Additionally, general economic, political and market conditions, such as recessions, interest rates or international currency fluctuations may adversely affect the market price of our common stock. Due to the limited volume of our shares which trade, we believe that our stock prices (bid, ask and closing prices) may not be related to our actual value, and not reflect the actual value of our common stock. Shareholders and potential investors in our common stock should exercise caution before making an investment in us.

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Additionally, as a result of the illiquidity of our common stock, investors may not be interested in owning our common stock because of the inability to acquire or sell a substantial block of our common stock at one time.  Such illiquidity could have an adverse effect on the market price of our common stock.  In addition, a shareholder may not be able to borrow funds using our common stock as collateral because lenders may be unwilling to accept the pledge of securities having such a limited market.  We cannot assure you that an active trading market for our common stock will develop or, if one develops, be sustained.

We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock.

We do not presently intend to pay any cash dividends on our common stock or to repurchase any shares of our common stock.  Any payment of future dividends will be at the discretion of the Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board of Directors deems relevant.  Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available.  Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price paid by you.

Because we are a small company, the requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the requirements of the Sarbanes-Oxley Act and the Dodd-Frank Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we must comply with the federal securities laws, rules and regulations, including certain corporate governance provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and the Dodd-Frank Act, related rules and regulations of the SEC and the NYSE MKT, with which a private company is not required to comply. Complying with these laws, rules and regulations will occupy a significant amount of time of our Board of Directors and management and will significantly increase our costs and expenses, which we cannot estimate accurately at this time.  Among other things, we must:

· establish and maintain a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

· prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

· maintain various internal compliance and disclosure policies, such as those relating to disclosure controls and procedures and insider trading in our common stock;

· involve and retain to a greater degree outside counsel and accountants in the above activities;

· maintain a comprehensive internal audit function; and

· maintain an investor relations function.

In addition, being a public company subject to these rules and regulations may require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage.  These factors could also make it more difficult for us to attract and retain qualified members of our Board of Directors, particularly to serve on our audit committee, and qualified executive officers.

Our Board of Directors can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of our company more difficult even if it might benefit our shareholders.

Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock.   Shares of preferred stock may be issued by our Board of Directors without shareholder approval, with voting powers and such preferences and relative, participating, optional or other special rights and powers as determined by our Board of Directors, which may be greater than the shares of common stock currently outstanding.  As a result, shares of preferred stock may be issued by our Board of Directors which cause the holders to have majority voting power over our shares, provide the holders of the preferred stock the right to convert the shares of preferred stock they hold into shares of our common stock, which may cause substantial dilution to our then common stock shareholders and/or have other rights and preferences greater than those of our common stock shareholders including having a preference over our common stock with respect to dividends or distributions on liquidation or dissolution.

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Investors should keep in mind that the Board of Directors has the authority to issue additional shares of common stock and preferred stock, which could cause substantial dilution to our existing shareholders.  Additionally, the dilutive effect of any preferred stock which we may issue may be exacerbated given the fact that such preferred stock may have voting rights and/or other rights or preferences which could provide the preferred shareholders with substantial voting control over us subsequent to the date of this filing and/or give those holders the power to prevent or cause a change in control, even if that change in control might benefit our shareholders.  As a result, the issuance of shares of common stock and/or preferred stock may cause the value of our securities to decrease.

Securities analysts may not cover, or continue to cover, our common stock and this may have a negative impact on our common stock’s market price.

The trading market for our common stock will depend, in part, on the research and reports that securities or industry analysts publish about us or our business. We do not have any control over independent analysts. We may not be able to obtain additional research coverage by independent securities and industry analysts. If no independent securities or industry analysts cover us, the trading price for our common stock could be negatively impacted. If one or more of the analysts cover us and such analysts downgrade our common stock, change their opinion of our shares or publish inaccurate or unfavorable research about our business, our stock price could decline. If one or more of these analysts ceases coverage of us or fails to publish reports on us regularly, demand for our common stock could decrease and we could lose visibility in the financial markets, which could cause our stock price and trading volume to decline.

Shareholders may be diluted significantly through our efforts to obtain financing and satisfy obligations through the issuance of securities.

Wherever possible, our Board of Directors will attempt to use non-cash consideration to satisfy obligations.  In many instances, we believe that the non-cash consideration will consist of shares of our common stock, preferred stock or warrants to purchase shares of our common stock. Our Board of Directors has authority, without action or vote of the shareholders, to issue all or part of the authorized but unissued shares of common stock, preferred stock or warrants to purchase such shares of common stock. In addition, we may attempt to raise capital by selling shares of our common stock, possibly at a discount to market in the future. These actions will result in dilution of the ownership interests of existing shareholders and may further dilute common stock book value, and that dilution may be material. Such issuances may also serve to enhance existing management’s ability to maintain control of us, because the shares may be issued to parties or entities committed to supporting existing management.

A decline in the price of our common stock could affect our ability to raise further working capital and adversely impact our operations.

A decline in the price of our common stock could result in a reduction in the liquidity of our common stock and a reduction in our ability to raise additional capital for our operations. Because our operations to date have been largely financed through the sale of equity securities, a decline in the price of our common stock could have an adverse effect upon our liquidity and our continued operations. A reduction in our ability to raise equity capital in the future could have a material adverse effect upon our business plan and operations, including our ability to continue our current operations.

Trading of our stock may become restricted by the SEC’s penny stock regulations and FINRA’s sales practice requirements, which may limit a stockholder’s ability to buy and sell our stock.

Our common stock will be subject to the “Penny Stock” Rules of the SEC, which will make transactions in our common stock cumbersome and may reduce the value of an investment in our common stock.

Our common stock is quoted on the OTC Bulletin Board, which is generally considered to be a less efficient market than markets such as NASDAQ or the national exchanges. Further, our securities will be subject to the “penny stock rules” adopted pursuant to Section 15(g) of the Exchange Act. The penny stock rules apply generally to companies whose common stock trades at less than $5.00 per share, subject to certain limited exemptions. Such rules require, among other things, that brokers who trade “penny stock” to persons other than “established customers” complete certain documentation, make suitability inquiries of investors and provide investors with certain information concerning trading in the security, including a risk disclosure document and quote information under certain circumstances. Many brokers have decided not to trade “penny stock” because of the requirements of the “penny stock rules” and, as a result, the number of broker-dealers willing to act as market makers in such securities is limited. In the event that we remain subject to the “penny stock rules” for any significant period, there may develop an adverse impact on the market, if any, for our securities. Because our securities are subject to the “penny stock rules”, investors will find it more difficult to dispose of our securities. Further, it is more difficult: (i) to obtain accurate quotations, (ii) to obtain coverage for significant news events because major wire services, such as the Dow Jones News Service, generally do not publish press releases about such companies, and (iii) to obtain needed capital.

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In addition to the “penny stock” rules promulgated by the SEC, FINRA has adopted rules that require a broker-dealer to have reasonable grounds for believing that an investment is suitable for a customer when recommending the investment to that customer. Prior to recommending speculative low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2.PROPERTIES

The Company’s oil and gas properties are described in greater detail above under “Item 1. Business”.

Office Lease

In March 2011, we executed a lease for office space in Houston, Texas.  The lease term was three years and we had an option to extend the lease for an additional three years.  Our scheduled rent was  $6,406 per month plus common area maintenance cost for the first year, $6,673 plus common area maintenance cost for the second year, and $6,940 per month plus common area maintenance cost for the third year.  We did not elect to extend this lease when it expired in March of 2014.  During 2013 we rented office space at 545 N. Upper Broadway, Suite 900, Corpus Christi, Texas, 78401 for $3,200 per month.  In September 2013, we terminated our lease for office space in Corpus Christi, Texas.

In February 2014, we agreed to sublease 4,915 square feet of office space from Greenshale Energy, LLC located at 800 Gessner Rd., Houston, Texas 77024.  The lease has a term through December 31, 2017.  Monthly rent of $10,650 is due under the lease from March 1, 2014 through December 31, 2014; $10,854 is due under the lease from January 1, 2015 through December 31, 2015; $11,059 is due under the lease from January 1, 2016 through December 31, 2016; and $11,264 is due under the lease from January 1, 2017 through December 31, 2017.

Rent expense during the years ended July 31, 2014 and 2013 was $186,463 and $211,346, respectively. See Note 8 – Notes Payable in the attached financial statements for details regarding our commitments related to our future obligations.

ITEM 3.  LEGAL PROCEEDINGS

As of July 31, 2014, we were party to the following legal proceedings:

Cause No. 2011-37552; Strategic American Oil Corporation v. ERG Resources, LLC, et al.; In the 55th District Court, Harris County, Texas. The Company is a plaintiff in this suit. In this case, Company brought claims for injunctive relief, breach of contract and fraudulent inducement against the defendant regarding the purchase of Galveston Bay Energy, LLC from ERG. The Company intends to prosecute its claims and defenses vigorously. As of the date of filing of this report, the Company is no longer seeking injunctive relief. Additionally, the below listed case has been consolidated into this case since the subject matter of the below case is subsumed within the subject matter of this case. From this point forward, there will be only this one piece of litigation. The trial was held in October 2013. The judge ruled in favor of ERG and that Hydrocarb is liable to pay the charges in the below-mentioned case and a portion of ERG’s attorney fees. The Company is in the process of post-trial motions and no judgment has been entered as of this date.

Cause No. 2011-54428; ERG Resources, LLC v. Galveston Bay Energy, LLC, in the 125th Judicial District Court, Harris County, Texas. This case deals with the operating agreements for the processing of product by the entities owned by ERG. It is an action seeking payments of charges and expenses by ERG that are refuted by GBE. The Company intends to prosecute its claims and defenses vigorously. As indicated above, this case has been consolidated into the case listed above. As such, the claims in this case will be decided in cause No. 2011-37552, which was tried in October 2013.

Settlement negotiations on both of these matters have been concluded. Galveston Bay has paid $35,000 in cash and Hydrocarb Energy will issue $65,000 in common stock to settle. More than this amount has been accrued previously and no further adjustments will be made to our financial statements.

A state regulator has requested that we renew certain pipeline easements located in Galveston Bay. The easements in question were originally obtained by another company whose successor filed for bankruptcy protection. Our subsidiary, Galveston Bay Energy, LLC purchased certain assets from the bankruptcy estate; however, based on the bankruptcy court’s order and the purchase and sale agreement, we believe the pipelines and easements in question were not included in assets purchased. The easements in question were scheduled to renew at various dates between 2012 and 2021. Based on current posted rates, the cost of renewal of all of the easements would be approximately $400,000. We have engaged legal counsel to dispute the regulator’s claim. If we are obligated to renew these easements, they would be part of the asset retirement obligation that was acquired with our subsidiary, Galveston Bay Energy, LLC. As such, the potential liability for these easements is factored into the computation of the asset retirement obligation (See Note 7 – Asset Retirement Obligation) that is estimated using the guidance in ASC 410-20, Asset Retirement and Environmental Obligations. On August 29, 2014, we filed a lawsuit in the state district court in Chambers County, Texas asking the Court to reform an assignment and assumption agreement in the property records of Chambers County. The General Land Office has asserted claims against us under various miscellaneous easements, claiming we are obligated to either renew the easement or remove any pipeline laid in the easement. We have disclaimed any obligations under these easements.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Shares of our common stock became quoted on the OTC Bulletin Board under the symbol “SGCA” on August 14, 2008.  On May 17, 2012, in connection with our name change, our symbol changed to “DUMA”.  On February 18, 2014, in connection with our name change, our symbol changed to “HECC”.

The following tables set forth the high and low sales price for one share of our common stock, as quoted on the OTCBB. These over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not represent actual transactions.  The prices below are adjusted for the 1:3 reverse stock split on May 8, 2014.  We do not have any securities that are currently traded on any other exchange or quotation system.

Quarter Ended	High		Low
July 31, 2014	$	6.00	$	3.45
April 30, 2014	$	8.25	$	4.56
January 31, 2014	$	8.10	$	5.43
October 31, 2013	$	6.75	$	5.43
July 31, 2013	$	8.25	$	5.58
April 30, 2013	$	6.75	$	5.85
January 31, 2013	$	6.75	$	4.56
October 31, 2012	$	7.47	$	4.23

Holders

As of October 22, 2014, we had 108 shareholders of record.

Dividend Policy

No dividends have been declared or paid on our common stock. We have incurred recurring losses and do not currently intend to pay any cash dividends in the foreseeable future.

Securities Authorized For Issuance Under Compensation Plans

The following table sets forth information as of July 31, 2014:

Equity Compensation Plan Information

		Number of Securities to be Issued Upon Exercise of Outstanding Options, warrants and Rights		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights			Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (excluding securities reflected in column (a))
		(a)		(b)			(c)
(a)	Equity compensation plans approved by security holders		N/A			N/A		N/A
(b)	Equity compensatin plans not approved by security holders
1.  2013 Stock Incentive Plan			265,333		$	7.14		770,136
2.  Compensation Warrants			1,084,584		$	7.50		N/A

2013 Stock Incentive Plan

During February 2013, the Board of Directors authorized and approved the adoption of the 2013 Stock Incentive Plan (2013 Plan). An aggregate of 883,333 shares of common stock may be issued under the plan.

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The Plan is administered by the Board of Directors, which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.

An award may not be exercised after the termination date of the award and may be exercised following the termination of an eligible participant’s continuous service only to the extent provided by the administrator under the 2013 Plan. If the administrator under the 2013 Plan permits a participant to exercise an award following the termination of continuous service for a specified period, the award terminates to the extent not exercised on the last day of the specified period or the last day of the original term of the award, whichever occurs first. In the event an eligible participant’s service has been terminated for “cause”, he or she shall immediately forfeit all rights to any of the awards outstanding.

The foregoing summary of the 2013 Plan is not complete and is qualified in its entirety by reference to the 2013 Plan, a copy of which is filed herewith.

During the year ended July 31, 2014, we granted no options to purchase shares of our common stock under the 2013 Plan.  During the year ended July 31, 2014, options to purchase 246,667 shares of our common stock expired unexercised, which increased the number of shares available to be issued under the 2013 Plan. As of July 31, 2014, a total of 770,136 shares were available to be issued under the 2013 Plan.

Recent Sales of Unregistered Securities

Other than listed below, we have previously disclosed in our Quarterly Reports on Form 10-Q and/or Current Reports on Form 8-K all unregistered equity securities that we issued during our fiscal year ended July 31, 2014.

In October 2013, the Company issued 619,960 shares of common stock to HCN to settle its debt obligations for fees (the “Fee”) related to consulting services provided by HCN with the acquisition of NEI, interest and late fees associated with the interest, and joint interest billings for work on the Namibian concession.  As part of the NEI acquisition the Company entered into a Consulting Services Agreement with HCN which obligated the Company to pay a $2,400,000 consulting fee to HCN for services.  Additionally, the shares issued also covered obligations of $553,630 of interest and late fees associated with the Fee, and $635,937 of joint interest billings payable to HCN for its work on the Namibian concession.  The shares were valued and recorded at $3,589,567, based on the value of the obligations settled.  On December 9, 2013 (“Acquisition Date”), the Company acquired HCN (“HCN Acquisition”) pursuant to a Share Exchange Agreement (“HCN Agreement”) dated November 27, 2013. In anticipation of the HCN Acquisition, HEC issued 619,960 shares of its common stock to HCN as full payment for HEC’s indebtedness to HCN in the amount of $3,589,567.  A condition to the Agreement closing was that HCN would sell the 619,960 shares before closing of the acquisition, which it did.

During December 2013 and January 2014, we issued an aggregate of 50,061 shares of common stock to six employees and consultants for services rendered.  We valued these transactions at approximately $308,000.  These transactions were made in reliance upon exemptions from registration under Section 4(2) of the Securities Act.  Each certificate issued for unregistered securities contained a legend stating that the securities have not been registered under the Securities Act and setting forth the restrictions on the transferability and the sale of the securities.  No underwriter participated in, nor did we pay any commissions or fees to any underwriter, in these transactions. These transactions did not involve a public offering. The investors were knowledgeable about our operations and financial condition.  The investors had knowledge and experience in financial and business matters that allowed them to evaluate the merits and risk of receipt of these securities.

During June and July 2014, we issued an aggregate of 117,843 shares of common stock to seven employees, directors and consultants for services rendered.  We valued these transactions at approximately $507,000.  These transactions were made in reliance upon exemptions from registration under Section 4(2) of the Securities Act.  Each certificate issued for unregistered securities contained a legend stating that the securities have not been registered under the Securities Act and setting forth the restrictions on the transferability and the sale of the securities.  No underwriter participated in, nor did we pay any commissions or fees to any underwriter, in these transactions. These transactions did not involve a public offering. The investors were knowledgeable about our operations and financial condition.  The investors had knowledge and experience in financial and business matters that allowed them to evaluate the merits and risk of receipt of these securities.

In August 2014, in connection with our entry into the Credit Agreement described below under “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations”, under the “Shadow Tree Credit Agreement” within the “Results of Operations” section, we issued the Lender 60,000 shares of our common stock.  We also agreed to issue the Lender (i) 32,500 shares of common stock issuable to Lender on the 12 month anniversary of the closing date; (ii) 32,500 shares of common stock issuable to Lender on the 18 month anniversary of the closing date; and (iii) 25,000 shares of common stock issuable to the Lender on the 21 month anniversary of the closing date, assuming in each of (i) through (iii), that there is any principal amount of loans outstanding or accrued and unpaid fees outstanding or due under the loans or Credit Agreement on such applicable dates.

In October and November of 2014, the following shares were issued: 10,000 shares to ProActive Capital Group, an investor and public relations firm; 1,316 shares to S. Chris Herndon as director compensation; 2,632 shares to Kent Watts as director compensation; and 22,034 shares to ERG in settlement of their lawsuit. These shares are not included in the ownership calculations used throughout this document.

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In September 2014, we entered into a consulting agreement with a third party, pursuant to which the consultant agreed to provide us investor relations and public relations consulting services for a period of six months and we agreed to provide the consultant consideration of $4,000 per month and 10,000 shares of common stock due upon execution.

The issuances described above were exempt from registration pursuant to Section 4(2) and/or Rule 506 of Regulation D of the Securities Act since the foregoing issuances did not involve a public offering, the recipients took the securities for investment and not resale, we took appropriate measures to restrict transfer, and the recipients were (a) “accredited investors”; or (b) had access to similar documentation and information as would be required in a Registration Statement under the Securities Act.

Description of Capital Stock

Common Stock

Holders of our common stock: (i) are entitled to share ratably in all of our assets available for distribution upon liquidation, dissolution or winding up of our affairs; (ii) do not have preemptive, subscription or conversion rights, nor are there any redemption or sinking fund provisions applicable thereto; and (iii) are entitled to one vote per share on all matters on which stockholders may vote at all stockholder meetings.  Each shareholder is entitled to receive the dividends as may be declared by our directors out of funds legally available for dividends. Our directors are not obligated to declare a dividend. Any future dividends will be subject to the discretion of our directors and will depend upon, among other things, future earnings, the operating and financial condition of our Company, our capital requirements, general business conditions and other pertinent factors.

The presence of the persons entitled to vote a majority of the outstanding voting shares on a matter before the stockholders shall constitute the quorum necessary for the consideration of the matter at a stockholders’ meeting.

The vote of the holders of a majority of the shares entitled to vote on the matter and represented at a meeting at which a quorum is present shall constitute an act of the stockholders, except for the election of directors, who shall be appointed by a plurality of the shares entitled to vote at a meeting at which a quorum is present.

Series A Preferred Stock

On December 2, 2013, we filed a Certificate of Designation that created a new class of stock: Series A 7% Convertible Voting Preferred Stock (“Series A Preferred”).  Up to 10,000 shares of Series A Preferred are authorized. The Series A Preferred has a stated value of $400 per share, pays annual dividends at 7%, and is convertible into the Company’s common stock, at the holder’s option, at a conversion rate of $6.00 per share. The Series A Preferred is neither redeemable nor is it callable. 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).

In connection with the acquisition of HCN on December 9, 2013, the Company issued 8,188 shares of our Series A Preferred Stock to a former Preferred Stock shareholder of HCN.  During the year ended July 31, 2014, the holder of the Series A Preferred Stock earned dividends of $150,548.  As of July 31, 2014, these dividends have not been accrued as liabilities since they were not declared by the Company.

ITEM 6.  SELECTED FINANCIAL DATA

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required under this item.

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of our financial condition, changes in financial condition, plan of operations and results of operations should be read in conjunction with (i) our audited consolidated financial statements as at July 31, 2014 and 2013 and (ii) the section entitled “Business”, included in this annual report. The discussion contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including, but not limited to, those set forth under “Risk Factors” and elsewhere in this annual report.

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Executive Summary

The following table shows the comparison for the last two years in certain key areas. Our focus, managerially, is on building revenue and cash flow. Our acquisition strategy will be driven by these same two criteria. We believe that shareholder returns and value will be most enhanced, at least in the short term, by focusing on increasing both revenue and cash flow.

	2014			2013
Revenue	$	5,065,096		$	7,070,540
Cash flow from operations	$	(456,658	)	$	657,472
Total assets	$	25,732,155		$	27,092,095
Net loss	$	(6,549,322	)	$	(37,525,733	)
Total stockholders' equity	$	9,958,651		$	12,486,803

Recent Highlights:

· Acquired new aerial gravity magnetic survey data over entire 5.3 million acre concession in Namibia, Africa.

· Partially completed first phase of multi-well development program in Galveston Bay.

· Made additional infrastructure improvements to assure limited downtime over winter months.

· Hired Charles F. Dommer as President to spearhead the operations and exploration efforts domestically and internationally.

· Shut-down offices in Corpus Christi, Texas and eliminated redundant personnel. Cost savings are estimated to be approximately $30,000 monthly.

Near Term Focus and Plans:

· Continue multi-well development program in Galveston Bay, Texas to enhance production, cash flow and reserves.

· Seek new partner to assist in financing new 2D seismic acquisition program in Namibia.

· Add new independent directors that can enhance our growth opportunities and expand the Company’s influence.

· Up-list to either NASDAQ or NYSE MKT stock markets to maximize liquidity and access to capital, contingent on meeting uplisting criteria.

Plan of Operations

In Galveston Bay, Texas we plan to continue enhancing the production from our four productive fields. Our development program includes 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, if successful, can almost quadruple current production enhancing cash flow significantly. 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.

In Namibia, Africa, we plan to interpret the newly acquired aerial gravity magnetic survey data and develop the acquisition plan for new 2D seismic data over the concession. This will include seeking a new partner that will, at least partially, carry us through the seismic acquisition program. 3D seismic will later be utilized for those identified structures which appear most prospective. Drilling of the first well is several years away. In the meanwhile, our goals are to increase the value and decrease the risk profile of our concession acreage in Namibia.

As of the date of this amendment, it has been determined by the Board of Directors to shut down the operations of our subsidiary Otaiba Hydrocarb LLC, in Abu Dhabi, United Arab Emirates. In September 2014, our CEO traveled to Abu Dhabi and met with the board of directors of Otaiba Hydrocarb LLC. His goal was to proceed with oil company registration work that would allow the company to receive bids on oilfield services work with the hopes of developing profitable business as has been the plan since the subsidiary was established. Instead of being able to proceed with the business plan, the partner in the UAE made it clear that they wanted more control over management of the subsidiary while still requiring us to find ongoing expenses. This requirement created an impasse between our partners and us. Together with consideration for the severe drop in oil prices, the board of directors made the decision to cease operations in the UAE without obtaining any contracts, in favor of our focus on oilfield services to be developed domestically. Thus, the decision was made to close the office in the UAE and not continue its operations, thereby reducing cash expense obligations that we have had in the past but will no longer have.

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Results of Operations

The following table sets out our consolidated losses for the periods indicated:

	Years Ended July 31,						Increase /			Percentage
	2014			2013			(Decrease)			Change
Revenues	$	5,065,096		$	7,070,540		$	(2,005,444	)		(28.40	)%
Operating expenses
Lease operating expense		4,913,313			4,560,201			353,112			7.70	%
Depreciation, depletion, and amortization		910,837			1,121,018			(210,182	)		(18.70	)%
Accretion		1,043,928			1,056,508			(12,580	)		(1.20	)%
Consulting fees - related party		6,754			196,384			(189,630	)		(96.60	)%
Acquisition-related costs - related party		-			34,834,752			(34,834,752	)		(100.00	)%
General and administrative expense		4,585,450			4,198,747			386,704			9.20	%
Total operating expenses		11,460,282			45,967,610			(34,507,328	)		(75.20	)%
Loss from operations		(6,395,186	)		(38,897,070	)		32,501,884			(83.60	)%
Consulting and other income (expense)		23,134			1,145,997			(1,122,863	)		(98.00	)%
Interest expense, net		(132,955	)		(149,131	)		16,176			(10.80	)%
Loss on sale of available for sale securities		-			(517,920	)		517,920			(100.00	)%
Impairment of available for sale securities		-			(275,327	)		275,327			(100.00	)%
Gain on derivative warrant liability		-			1,056,224			(1,056,224	)		(100.00	)%
Loss on disposal of assets		(23,990	)		(14,054	)		(9,936	)		70.70	%
Foreign currency transaction (loss)		(21,253	)		(5,884	)		(15,369	)		261.20	%
Net loss before income taxes		(6,550,250	)		(37,657,165	)		31,106,915			(82.80	)%
Income tax provision		(4,599	)		122,949			(127,548	)		(103.70	)%
Net loss		(6,554,849	)		(37,534,216	)		30,979,367			(82.50	)%
Less:  Net loss attributable to noncontrolling interests		(5,527	)		(8,483	)		(2,956	)		(34.80	)%
Net loss		(6,549,322	)		(37,525,733	)		30,976,411			(82.50	)%
Dividend on preferred stock		(34,254	)		(69,920	)		35,666			(51.00	)%
Deemed dividend on preferred stock		(150,548	)		-			(150,548	)		100.00	%
Accretion dividend - Beneficial Cash Feature on preferred stock		(949,808	)		-			(949,808	)		100.00	%
Net loss after dividends	$	(7,683,932	)	$	(37,595,653	)	$	29,911,721			(79.60	)%

We recorded a net loss attributable to Hydrocarb Energy Corp. after dividends of $7,683,932, or $(0.51) per basic and diluted common share, during the fiscal year ended July 31, 2014, as compared to an amount of $37,595,653, or $(8.66) per basic and diluted common share, during the fiscal year ended July 31, 2013.

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

· Revenues decreased from $7,070,540 in the prior year to $5,065,096 in the current year, a decrease of $2,005,444 or 28%.  Approximately $1,500,000 of the total revenue decrease was due to lower production in 2014, compared to 2013.  Oil production decreased by 31% and gas production decreased by 2%, primarily as a result of freezing weather and equipment failure, as well as the sale of ownership of the Welder leases during the third quarter of 2014. Pricing decreased caused approximately $500,000 of the revenue decrease. Oil pricing decreased by 3% in 2014 to an average of $102.87 per barrel, while gas prices decreased by 9% to $70.98, as a result of market pricing.

· Lease operating expenses increased from $4,560,201 in the prior year to $4,913,313 in the current year, an increase of $353,112 or 8%.  This increase was due to higher operating costs caused by significant well repairs in the current year, which did not occur in the prior year.

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· Depreciation, depletion, and amortization decreased from $1,121,018 in the prior year to $910,836 in the current year, a decrease of $210,182.  This decrease was due to lower production in the current year versus production in the same period of last year.

· Consulting fees – related party pertained to warrants granted as compensation to a company for investor relations and public relations services.  This company is a related party, as it is controlled by Michael Watts, the father-in-law of our former CEO, Jeremy Driver and brother of our current CEO.  The warrant grant occurred in April 2011 and consisted of immediately vesting warrants and warrants that vest in accordance with a market condition. The warrants that vested immediately were valued using the Black-Sholes option pricing method and the expense was recognized on the vesting date.  The warrants with a market condition were valued using a lattice model and the expense was amortized over the service period, which was completed during the first quarter of fiscal year 2014.

· Acquisition related costs – related party: During the year ended July 31, 2013, we incurred $34,834,752 of expense in conjunction with our acquisition of NEI. The transaction, which was a related party transaction, is discussed in detail in Note 2 of our Consolidated Financial Statements included herein. This charge is the most significant difference in the results of operations from the comparable period in fiscal year 2014. As of July 31, 2013, we had recognized $34,834,752 of expense associated with the acquisition of NEI, which consisted of the assumption of NEI’s net liability of $1,837,952, $3,784,800 associated with the 2,490,000 shares issued at the closing date of the acquisition and $29,212,000 associated with the contingent consideration.  No similar transaction was recognized during the year ended July 31, 2014.

· General and administrative expenses increased from $4,198,747 in the prior year to $4,585,451 in the current year, an increase of $386,704 or 9%. This increase was the result of higher professional fees and compensation expense in the current year.

· Consulting and other income primarily represents income earned for geological consulting services and asset acquisition consulting.  This item decreased from $1,145,997 in the prior year to $23,134 in the current year.  The decrease was due to the completion of the consulting project at HCN.

· We incurred a loss on the sale of securities and an impairment on securities during the year ended July 31, 2013 due to the other-than-temporary decline in value and subsequent sale of securities that had declined in value since the time of acquisition. During the fiscal year in 2014, we did not own or transact in investment securities.

· We re-measured our derivative warrants at fair value at every reporting date until the derivative feature expired in October and November 2012. Change in the fair value of the derivative warrants, as determined using a lattice model, during the year ending July 31, 2013 resulted in a gain of $1,056,224 during the year ended July 31, 2013.  We had no derivative warrants requiring revaluation during fiscal year 2014.

The following table sets forth our cash and working capital as follows:

	2014			2013
Cash and cash equivalents	$	144,258		$	354,829
Restricted cash	$	6,877,944		$	6,920,739
Working capital (deficit)	$	(3,566,332	)	$	(2,341,541	)

Shadow Tree 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 lenders party thereto (the “Lenders”).  Pursuant to the Credit Agreement, the Lenders loaned us $4 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.

Pursuant to the Credit Agreement, we have the right, at any time prior to the one year anniversary of the Credit Agreement, to borrow up to an additional $1,000,000 under the Credit Agreement (the “Additional Loan”), subject to certain pre-requisites and requirements as set forth in the Credit Agreement, including, but not limited to us raising $750,000 through the sale of equity subsequent to the closing of the transactions contemplated by the Credit Agreement (which we agreed to obtain within 150 days of the date of the Credit Agreement).  We also agreed to pay a 2% Structuring Fee on the Additional Loan. The proceeds of the Additional Loan may only be used for the Oil and Gas Activities.

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The amount owed pursuant to the Notes (and any amount borrowed pursuant to the Additional Loan) is guaranteed by our wholly-owned subsidiary, Hydrocarb Corporation (“HC”) and its subsidiaries, and our other wholly-owned subsidiaries and is secured by a first priority security interest in substantially all of our assets (including, but not limited to the securities of our subsidiaries and HC and its subsidiaries) evidenced by a Guarantee and Collateral Agreement, various pledge agreements and a deed of trust providing the Agent, as agent for the Lenders, a security interest over our oil and gas assets and rights.

The Notes do not accrue any interest for the first nine months after their issuance date (August 15, 2014), provided thereafter they accrue interest at the rate of (a) 16% per annum where the average net monthly oil and gas production revenues of Galveston Bay Energy LLC, our wholly-owned subsidiary, for the trailing three month period (the “Trailing Three Month Revenues”) is less than $900,000; or (b) 14% per annum, where the Trailing Three Month Revenues are equal to or greater than $900,000, payable monthly in arrears through the maturity date of such Notes, August 15, 2016.  The Additional Loan, if any, will bear interest at the rate of 14% per annum, payable monthly in arrears, and will have the same maturity date as the Notes.  Upon the occurrence of an event of default, the Notes (and any amount outstanding under the Additional Loan) will bear interest at the rate of 24% per annum until paid in full.

Pursuant to the Credit Agreement, we agreed to issue the Lenders their pro rata share of (a) 60,000 restricted shares of common stock on the effective date of the Credit Agreement, August 15, 2014 (the “Effective Date”); (b) 32,500 restricted shares in the event any amount of the Loans (or other obligations outstanding under agreements entered into in connection with the Loans, the “Loan Documents”) are outstanding on the 12 month anniversary of the Effective Date; (c) 32,500 restricted shares in the event any amount is outstanding under the Loan Documents on the 18 month anniversary of the Effective Date; and (d) 25,000 restricted shares in the event any amount is outstanding under the Loan Documents on the 21 month anniversary of the Effective Date.  The shares are to be 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.

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.

The Credit Agreement includes customary events of default for facilities of a similar nature and size as the Credit Agreement, including, but not limited to, if any breach or default occurs under the Loan Documents, the failure of the Company to pay any amount when due under the Loan Documents, if the Company (or its subsidiaries) is subject to any judgment in excess of $250,000 which is not discharged or stayed within 30 days, or if a change in control of the Company, any subsidiary or any guarantor should occur, defined for purposes of the Credit Agreement as any transfer of 25% or more of the voting stock of such entity.

Our plan of operations over the next twelve months is dependent, at least in part, upon one or more of the following occurring:

· Raising capital through the sale of equity;

· Raising capital through the sale of working interest in our producing properties;

· Borrowing money from lenders to perform the work;

· Freeing up previously restricted cash (State bonding requirement) as shut-in wells are brought back into production and/or as wells are plugged; and

· Performing work one project at a time (capital permitting) and using the increased cash flow to fund the next projects.

Our plan of operations over the next twelve months will be subject to available capital which will be determined by the success of projects that are currently in progress or will begin soon. It is even possible that given a high degree success in recently initiated projects and upcoming projects we could actually exceed our planned operations and have more internally-derived funds available for capital expenditures for the next 12 months. As management, we will determine the best use of our capital given the circumstances at the time.

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Various conditions outside of our control may detract from our ability to raise the capital needed to execute our plan of operations, including the price of oil as well as the overall market conditions in the international and domestic economies. We recognize that the United States economy and others have suffered through a period of uncertainty during which the capital markets have been highly volatile, and that there is no certainty that these markets will stabilize or improve. If the price of oil drops to levels seen in previous years, we recognize that it will adversely affect our cash flow from operations and our ability to raise additional capital. Any of these factors could have a material adverse impact upon our ability to raise capital or obtain financing and, as a result, upon our short-term or long-term liquidity.

Net Cash Used in Operating Activities

During the year ended July 31, 2014, net cash used in operating activities was $456,658 compared to net cash provided by operating activities of $657,472 during the year ended July 31, 2013.  The primary factor behind net cash used in operating activities was the net loss in each of the two years.

Net Cash Used in Investing Activities

During the year ended July 31, 2014, we used cash of $554,678 in investing activities compared to cash used of $1,150,033 during the year ended July 31, 2013. The use of cash in 2014 primarily consisted of investment in oil and gas assets totaling $1,052,679 and the purchase of property and equipment of $169,794, offset by the proceeds from the sale of oil and gas properties of $625,000. Cash used in investing activities during fiscal 2013 consisted primarily of purchase of oil and gas properties totaling $1,564,490, offset by the proceeds from the sale of available for sale securities of $287,874 and proceeds from sale of oil and gas properties of $195,563.

Net Cash Provided by Financing Activities

Financing activities during the year ended July 31, 2014 provided cash of $800,765 compared to $341,892 used in the prior year.  The primary factor in the current year was the net proceeds from borrowings from related parties and proceeds from collections on receivable from a stock sale.  In the prior year net borrowings from related parties provided the cash in the financing activities.

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, the fair value of our warrant derivative liability, and accounting for stock-based compensation.

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.

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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.

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 unit 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 proved 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. During the years ended July 31, 2013 and 2012, the ceiling exceeded the net book value of the property and it was not necessary to record an impairment charge.

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 Obligation

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 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 update our assessment accordingly. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gathering systems as these obligations are incurred.

Fair Value

Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.

Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.

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The three-level hierarchy is as follows:

· Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.

· Level 2 inputs consist of quoted prices for similar instruments.

· Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  We have determined that certain warrants outstanding during the period covered by these financial statements qualify as derivative financial instruments under the provisions of FASB ASC Topic No. 815-40, “Derivatives and Hedging – Contracts in an Entity’s Own Stock.” These warrant agreements include provisions designed to protect holders from a decline in the stock price (‘down-round’ provision) by reducing the exercise price in the event we issue equity shares at a price lower than the exercise price of the warrants.  As a result of this down-round provision, the exercise price of these warrants could be modified based upon a variable that is not an input to the fair value of a ‘fixed-for-fixed’ option as defined under FASB ASC Topic No. 815-40 and consequently, these warrants must be treated as a liability and recorded at fair value at each reporting date.

The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain (loss) on derivative warrant liability.”

Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.

We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2014 or July 31, 2013.

The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability as follows:

As of July 31,	2014		2013
Beginning of period	$	-	$	1,325,388
Expiration of derivative warrant feature		-		(269,164	)
Unrealized gain on changes in fair value of derivative liability		-		(1,056,224	)
End of period	$	-	$	-

The unrealized gain on changes in fair value was recorded as a reduction of the derivative liability and as an unrealized gain on the change in fair value of the liability in our statement of operations.

The warrant agreement provides that the anti-dilution provisions expire three years after the issuance of the warrants. Accordingly, the provision for warrants to purchase 408,065 and 206,400 shares of common stock expired on October 15, 2012 and November 13, 2012, respectively. As of each of those dates, the fair value of the warrant was determined for a final mark to market adjustment and the outstanding warrant derivative liability was reclassified to additional paid-in capital, as the warrants were no longer derivatives.

Stock-Based Compensation

ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.

We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.”  ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete.  Generally, our awards do not entail performance commitments.  When an award vests over time such that performance occurs over multiple reporting periods, 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.

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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.

See Note 1 of our Consolidated Financial Statements for our year ended July 31, 2014 for a summary of other significant accounting policies.

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.  See Note 13 of our Consolidated Financial Statements for a description of our multi-year commitments.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required under this item.

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ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA

HYDROCARB ENERGY CORP.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

TABLE OF CONTENTS

Report of Independent Registered Public Accounting Firm	43
Consolidated Balance Sheets as of July 31, 2014  and 2013	44
Consolidated Statements of Operations and Comprehensive Loss for the years ended July 31, 2014 and 2013	45
Consolidated Statements of Changes in Stockholders’ Equity for the years ended July 31, 2014 and 2013	46
Consolidated Statements of Cash Flows for the years ended July 31, 2014 and  2013	47
Notes to Consolidated Financial Statements	48

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The Board of Directors

Hydrocarb Energy Corp.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Hydrocarb Energy Corp. and its subsidiaries (collectively, the “Company”) as of July 31, 2014 and 2013 and the related consolidated statements of operations and comprehensive loss, cash flows and changes in stockholders’ equity for each of the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatements. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hydrocarb Energy Corp. and its subsidiaries as of July 31, 2014 and 2013, and the results of their operations and their cash flows for each of the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ MaloneBailey, LLP

www.malone-bailey.com

Houston, Texas

November 13, 2014

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HYDROCARB ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

	July 31, 2014			July 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	144,258		$	354,829
Oil and gas revenues receivable		372,120			725,691
Accounts receivable - related party		58,014			201,284
Other current assets		446,320			345,942
Other receivables, net		38,455			312,997
Total current assets		1,059,167			1,940,743
Oil and gas properties, accounted for using the full cost method of accounting Evaluated property, net of accumulated depletion of $3,491,420 and $2,617,478, respectively; and accumulated impairment of $373,335 and $373,335, respectively		15,288,370			16,867,029
Unevaluated property		2,119,769			1,124,805
Restricted cash		6,877,944			6,920,739
Other assets		219,942			180,726
Property and equipment, net of accumulated depreciation of $135,590 and $116,945, respectively		166,963			58,053
TOTAL ASSETS	$	25,732,155		$	27,092,095
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	2,795,675		$	2,816,084
Short term notes payable		334,688			259,644
Asset retirement obligation – short term		1,133,690			724,374
Advances		195,904			180,804
Due to related parties		165,542			301,378
Total current liabilities		4,625,499			4,282,284
Notes payable		-			142,992
Notes payable - related party		600,000			-
Asset retirement obligation – long term		10,582,540			10,209,024
Total liabilities		15,808,039			14,634,300
Stockholders' Deficit:
Series A 7% Convertible Preferred Stock, 10,000 shares authorized $400 par, 8,188 shares issued and outstanding as of July 31, 2014		3,275,200			-
Hydrocarb Corporation (“HCN”) Series A 7% Convertible Preferred Stock, $400 par					1,690,000
Common stock: $001 par value; 333,333,333 shares authorized; 21,081,602 and 4,427,071 shares issued and outstanding as of July 31, 2014 and 2013, respectively		21,082			4,427
Receivable for common stock		(2,184,879	)		-
Additional paid-in capital		78,953,599			75,137,401
Accumulated deficit		(70,106,351	)		(63,522,775	)
Treasury stock		-			(822,250	)
Total stockholders' equity		9,958,651			12,486,803
Non-controlling interests		(34,535	)		(29,008	)
Total equity		9,924,116			12,457,795
TOTAL LIABILITIES AND EQUITY		25,732,155			27,092,095

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

44

HYDROCARB ENERGY CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended July 31,
	2014			2013
Revenues	$	5,065,096		$	7,070,540
Operating expenses
Lease operating expense		4,913,313			4,560,201
Depreciation, depletion, and amortization		910,837			1,121,018
Accretion		1,043,928			1,056,508
Consulting fees - related party		6,754			196,384
Acquisition-related costs - related party		-			34,834,752
General and administrative expense		4,585,450			4,198,747
Total operating expenses		11,460,282			45,967,610
Loss from operations		(6,395,186	)		(38,897,070	)
Consulting and other income (expense)		23,134			1,145,997
Interest expense, net		(132,955	)		(149,131	)
Loss on sale of available for sale securities		-			(517,920	)
Impairment of available for sale securities		-			(275,327	)
Gain on derivative warrant liability		-			1,056,224
Loss on disposal of assets		(23,990	)		(14,054	)
Foreign currency transaction (loss)		(21,253	)		(5,884	)
Net loss before income taxes		(6,550,250	)		(37,657,165	)
Income tax provision		(4,599	)		122,949
Net loss		(6,554,849	)		(37,534,216	)
Less:  Net loss attributable to non-controlling interests		(5,527	)		(8,483	)
Net loss attributable to Hydrocarb Energy Corp.		(6,549,322	)		(37,525,733	)
Dividend on preferred stock		(34,254	)		(69,920	)
Deemed dividend on preferred stock		(150,548	)		-
Accretion dividend - Beneficial Cash Feature on preferred stock		(949,808	)		-
Net loss attributable to Hydrocarb Energy Corp. after dividends	$	(7,683,932	)	$	(37,595,653	)
Basic and diluted loss per common share:	$	(0.51	)	$	(8.66	)
Weighted average shares  outstanding  (basic and diluted)		15,150,782			4,342,864

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

45

HYDROCARB ENERGY CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

	HCN Preferred Stock						HEC Preferred Stock				HCN Common Stock						HEC Common Stock				Additional						Other			Stock
	Shares			Par Value			Shares		Par Value		Shares			Par Value			Shares		Par Value		Paid-in Capital			Treasury Stock			Comprehensive Income			Subscription Receivable			Accumulated Deficit			Total Equity
Restated Balance, July 31, 2012		-		$	-			-	$	-		-		$	-			3,597,071	$	3,597	$	38,342,757		$	-		$	(743,082	)	$	-		$	(25,927,122	)	$	11,676,150
Acquisition of NEI																		830,000		830		35,395,970															35,396,800
Issuance of HCN preferred stock		4,225			1,690,000																																1,690,000
HCN purchase of HEC common stock																									(822,250	)											(822,250	)
Share-based compensation:
Amortization of fair value of stock options																						933,126															933,126
Warrants granted to related party																						196,384															196,384
Expiration of derivative warrant liability																						269,164															269,164
Unrealized loss on available for sale securities																												743,082									743,082
Dividend on HCN Preferred Stock																																		(69,920	)		(69,920	)
Net loss attributable to HEC																																		(37,525,733	)		(37,525,733	)
Balance July 31, 2013		4,225		$	1,690,000			-	$	-		-		$	-			4,427,071	$	4,427		75,137,401		$	(822,250	)	$	-		$	-		$	(63,522,775	)	$	12,486,803
Issuance of HCN common stock												6,559,257			6,560							24,511															31,071
Issuance of HCN preferred stock to settle debt and accounts payable		3,963			1,585,200																																1,585,200
HCN sale of HEC common stock for receivable																						177,750			822,250						(1,000,000	)					-
HCN sale of HEC common stock for receivable																						(1,729,688	)		3,589,567						(1,859,879	)					-
HEC preferred stock exchanged in connection with HCN acquisition		(8,188	)		(3,275,200	)		8,188		3,275,200																											-
HEC common stock exchanged in connection with HCN acquisition												(6,559,257	)		(6,560	)		8,396,667		8,397		(1,837	)														-
HEC Common stock issued to satisfy contingently-issued rights from NEI Acquisition																		7,470,000		7,470		(7,470	)														-
HEC common stock  issued to settle debt																		619,960		620		3,588,947			(3,589,567	)											-
HEC Beneficial Conversion Feature on 7% Preferred stock																						949,808															949,808
Deemed Dividend on Preferred Stock																						(949,808	)														(949,808	)
Share-based compensation:
Amortization of fair value of stock options																						943,572															943,572
Stock issued to employees and directors																		167,904		168		813,659															813,827
Warrants granted to related party																						6,754															6,754
Dividend on HCN preferred stock																																		(34,254	)		(34,254	)
Cash collections on stock subscription receivable																															675,000						675,000
Net loss attributable to HEC																																		(6,549,322	)		(6,549,322	)
Balance July 31, 2014		-		$	-			8,188	$	3,275,200		-		$	-			21,081,602	$	21,082	$	78,953,599			-		$	-		$	(2,184,879	)	$	(70,106,351	)	$	9,958,651

On May 8, 2014, the Company effected a 1 for 3 reverse split. All share and per share amounts have been retroactively restated to reflect the reverse split.

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

46

HYDROCARB ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended July 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(6,554,849	)	$	(37,534,216	)
Adjustments to reconcile net income loss to net cash used in operating activities:
Depreciation, depletion and amortization		910,837			1,121,018
Accretion		1,043,928			1,056,508
(Gain) loss on sale of available for sale securities		-			517,920
Impairment of available for sale securities		-			275,327
Loss on disposal of assets		23,990			14,054
Change in allowance for doubtful accounts		11,948			57,491
Warrants granted to related party		6,754			196,384
Share based compensation		1,757,399			933,126
Acquisition-related costs - related party		-			34,834,752
Gain on derivative warrant liability		-			(1,056,224	)
Changes in operating assets and liabilities:
Accounts receivable		353,571			168,096
Other receivables		262,594			-
Accounts receivable - related party		143,270			(68,620	)
Other assets		263,510			(89,829	)
Accounts payable and accrued expenses		184,900			299,246
Accounts payable related party		1,244,054			125,021
Advances		15,100			125,643
Settlement of asset retirement obligation		(123,664	)		(318,225	)
NET CASH USED IN OPERATIONS		(456,658	)		657,472
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of oil and gas properties		(1,052,679	)		(1,564,490	)
Purchases of property and equipment		(169,794	)		(13,648	)
Proceeds from sale of oil and gas properties		625,000			195,563
Change in restricted cash		42,795			(30,739	)
Purchase of available for sale securities		-			(24,593	)
Proceeds from sale of available for sale securities		-			287,874
CASH USED IN INVESTING ACTIVITIES		(554,678	)		(1,150,033	)
CASH FLOWS FROM FINANCING ACTIVITIES
Payments on notes payable		(471,052	)		(271,972	)
Proceeds from note payable to related party		600,000			-
Proceeds from collections on receivable for stock sale		675,000			-
Proceeds from HCN issuance of common stock		31,071			-
Dividend on HCN preferred stock		(34,254	)		(69,920	)
CASH PROVIDED BY FINANCING ACTIVITIES		800,765			(341,892	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(210,571	)		(834,453	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		354,829			1,189,282
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	144,258		$	354,829

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

47

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Description of business and basis of presentation

We are a natural resource exploration and production company engaged in the exploration, acquisition, development, and production of oil and gas properties in the United States and onshore in Namibia, Africa.  We were incorporated under the laws of the State of Nevada on April 12, 2005 under the name “Carlin Gold Corporation”. On July 19, 2005, we changed our name to “Nevada Gold Corp.” On October 18, 2005, we changed our name to “Gulf States Energy, Inc.” and increased our authorized capital from 100,000,000 shares of common stock to 500,000,000 shares of common stock, par value $0.001 per share. On September 5, 2006, we changed our name to “Strategic American Oil Corporation”.  On April 4, 2012 we completed a one new share for twenty-five old share (1:25) reverse stock split and as a result our authorized capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock.  Also, effective April 4, 2012, we changed our name to “Duma Energy Corp.”  Effective May 16, 2012, we increased our authorized capital from 20,000,000 shares to 500,000,000 shares of common stock.  Effective November 29, 2013, the Company increased the number of its authorized shares of common stock from 500,000,000 to 1,000,000,000 shares of common stock.    Effective February 18, 2014, we changed our name from Duma Energy Corp. to Hydrocarb Energy Corp.  Effective May 8, 2014, we effected a 1:3 reverse split of our authorized common stock and a corresponding 1:3 reverse split of our outstanding common stock.  All share and per share amounts for all periods in this report have been retroactively restated to reflect the reverse split. Our capitalization at July 31, 2014 was 333,333,334 authorized common shares with a par value of $0.001 per share.  Our common stock is quoted under the symbol “HECC” on the OTCBB.

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.

We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas limited liability company, (iii) SPE Navigation I, LLC, a Nevada limited liability company, (iv) Namibia Exploration, Inc., a Nevada corporation, (v) Hydrocarb Corporation, a Nevada corporation, (vi) Hydrocarb Texas Corporation, a Texas corporation, and (vii) Hydrocarb Namibia Energy (Pty) Limited, a company chartered in the Republic of Namibia.  In addition, we own 95% of the issued and outstanding share capital of Otaiba Hydrocarb LLC, a UAE limited liability corporation.

As of July 31, 2014, we maintain developed and undeveloped acreage offshore in Texas.  As of July 31, 2014, we were producing oil and gas from our working interest in four offshore fields in Galveston Bay, Texas.  During September 2012, we acquired, through the acquisition of Namibia Exploration Inc., a 39% non-operated working interest in a concession located onshore in Namibia, Africa.  During December 2013, with our acquisition of Hydrocarb Corporation, we acquired 51% working interest in this onshore Namibia, Africa concession and now own 90% working interest (100% cost responsibility) in the Namibia, Africa concession.

Reclassifications

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

Principles of consolidation

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 accompanying consolidated financial statements include the accounts of Hydrocarb Energy Corp., our wholly owned subsidiaries Penasco Petroleum Corporation (“Penasco”), SPE Navigation I, LLC (“SPE”), Galveston Bay Energy, LLC (“GBE”), Namibia Exploration, Inc. (“NEI”), Hydrocarb Corporation (“HCN”), Hydrocarb Texas Corporation, and Hydrocarb Namibia Energy (Pty) Limited.  In addition, these financials include our 95% ownership interest in Otaiba Hydrocarb LLC.  All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

48

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Significant areas requiring management’s estimates and assumptions include the determination of the fair value of transactions involving stock-based compensation and financial instruments, estimates of the costs and timing of asset retirement obligations, and oil and natural gas proved reserve quantities.  Oil and natural gas proved reserve quantities form the basis for the calculation of amortization of oil and natural gas properties and for asset impairment tests. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories.

Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.

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.

Receivables and allowance for doubtful accounts

Oil and gas revenues receivable are recorded at the invoiced amount and do not bear any interest. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Management has determined that a reserve for uncollectible amounts was not required in the periods presented.

Accounts receivable – related party includes the oil and gas revenue receivable from our Barge Canal properties, which, up until September 1, 2013, were operated by a company owned by one of our former officers who was also a director, and joint interest billings receivable from two working interest partners who are related to our former Chief Financial Officer, the former Chief Executive Officer and the current Chief Executive Officer. This balance also includes an oil and gas receivable from Lifestream, LLC, a company owned by the brother of our current CEO.

Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate.

We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.  As of July 31, 2014 and 2013, we have reserved $70,742 and $58,585, respectively, for potentially uncollectable other receivables.

Available for sale securities

We invest in marketable equity securities which are classified as available for sale. The first in first out method is used to determine the cost basis of our equity securities sold. Available-for-sale securities are marked to market based on the fair values of the securities determined in accordance with ASC Section 820 (Fair Value Measurement), with the unrealized gains and losses, net of tax, reported as a component of accumulated other comprehensive income (loss).

49

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other current assets

Other current assets consist primarily of prepaid insurance, prepaid interest expense, prepayments made towards properties not operated by us, and accrued interest on our deposits.

Concentrations

Our operations are concentrated in Texas and the majority of our operations are conducted offshore in Galveston Bay.  We operate in the oil and gas exploration and production industry. If the oil and natural gas exploration and production industry as a whole were adversely affected, for example by weather, supply shortages, or other factors, we would also experience adverse effects. Because our properties are offshore, we are also vulnerable to adverse weather.

For the year ended July 31, 2014, 83% of our revenue was attributable to one purchaser.  At July 31, 2014, this same purchaser accounted for 88% of our accounts receivable. For the year ended July 31, 2013, 85% of our revenue was attributable to one purchaser.  At July 31, 2013, this same purchaser accounted for 76% of our accounts receivable.

We place cash with high quality financial institutions and at times may exceed the federally insured limits. We have not experienced a loss in such accounts nor do we expect any related losses in the near term.

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.

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 unit 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.

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.

Impairment

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 proved 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.  During the years ended July 31, 2014 and July 31, 2013, the ceiling exceeded the net book value of the property and it was not necessary to record an impairment charge.

50

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset retirement obligation

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 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 update our assessment accordingly. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gathering systems as these obligations are incurred.

Restricted cash

Restricted cash consists of certificates of deposit that have been posted as collateral for letters of credit supporting bonds guaranteeing remediation of our oil and gas properties in Texas and escrow funds deposited directly with regulatory authorities. As of July 31, 2014 and 2013, restricted cash totaled $6,877,944 and $6,920,739, respectively.

Other assets

Other assets at July 31, 2014 and 2013 consisted primarily of prepaid land use fees, which are payments that cover multiple years (typically ten years) rental for easements and surface leases.  These are paid as they come due on an ongoing basis and amortized over the rental period.  In addition, other assets also include a domain name for $30,267, which is an intangible asset with an indefinite life due to the fact that it is renewable annually for nominal cost.  We evaluate intangible assets with an indefinite life for possible impairment at least annually by comparing the fair value of the asset with its carrying value.

Property and equipment, other than oil and gas

Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally three to five years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. We perform ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.

Impairment of long-lived assets

We periodically review our long-lived assets, other than oil and gas property, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. We recognize an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value. We recorded no impairment on our non-oil and gas long-lived assets during the years ended July 31, 2014 and 2013, respectively.

Advances

Advances consist of prepayments received from working interest partners pertaining to their share of the costs of drilling oil and gas wells.  Partners are billed in advance for the estimated cost to drill a well and as the work proceeds, the prepayment is applied against their share of the actual drilling cost.  As of July 31, 2014 and 2013, advances totaled $195,904 and $180,804, respectively.

Revenue recognition

We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. Actual sales of gas are based on sales, net of the associated volume charges for processing fees and for costs associated with delivery, transportation, marketing, and royalties in accordance with industry standards. Operating costs and taxes are recognized in the same period in which revenue is earned.  Severance and ad valorem taxes are reflected as a component of lease operating expense.

51

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Income taxes

We account for income taxes using the asset and liability method. Under this method, deferred income tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Fair value

Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.

Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.

The three-level hierarchy is as follows:

● Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.

● Level 2 inputs consist of quoted prices for similar instruments.

● Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  We have determined that certain warrants outstanding during the period covered by these financial statements qualify as derivative financial instruments under the provisions of FASB ASC Topic No. 815-40, “Derivatives and Hedging – Contracts in an Entity’s Own Stock.” (See Note 8 – Fair Value).

The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain on derivative warrant liability.”

Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.

We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2014 or July 31, 2013. The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable – related party, accounts payable and accrued expenses, and notes payable approximate their fair market value based on the short-term maturity of these instruments.

Stock-based compensation

ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.

We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.”  ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete.  Generally, our awards do not entail performance commitments.  When an award vests over time such that performance occurs over multiple reporting periods, 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 vesting date, which is presumed to be the date performance is complete.

52

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Stock Split

On May 8, 2014, we affected a 1-for-3 reverse stock split.  All share and per share amounts 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 or the effective date of the registration statement, whichever is later.

Earnings per share

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share includes the dilutive effects of common stock equivalents on an “as if converted” basis. For the years ended July 31, 2014 and 2013, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.

Contingencies

Legal

We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.  See Note 13 - Commitments and Contingencies for more information on legal proceedings.

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.

Accumulated Other Comprehensive Income (Loss), net of tax

We follow the provisions of ASC 220, "Comprehensive Income", which establishes standards for reporting comprehensive income. In addition to net loss, comprehensive loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company.

Recent accounting pronouncements

In March 2013, the FASB amended ACS 830, Foreign Currency Matters, to clarify the appropriate accounting when a parent ceases to have a controlling interest in a subsidiary or group of assets that is a business within a foreign entity. This clarification provides that the cumulative translation adjustment should only be released into net income if the loss of controlling interest represents complete or substantially complete liquidation of the foreign entity in which the subsidiary or asset group had resided. This amendment is effective for us starting with our first quarter of fiscal year 2015 and adoption would impact our consolidated financial condition and results of operations if we dispose of a foreign entity.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (“ASU No. 2014-09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance when it becomes effective. This new standard is effective for us starting with our first quarter of fiscal year 2018.  Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

53

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 – Acquisitions

HCN Acquisition

On December 9, 2013 (“Acquisition Date”), we acquired HCN (“HCN Acquisition”) pursuant to a Share Exchange Agreement (“HCN Agreement”) dated November 27, 2013.  The purchase price was 8,396,667 shares of HEC’s common stock to HCN’s shareholders in exchange for 100% of the outstanding equity interest in HCN and 8,188 shares of HEC Series A Preferred Stock to a holder of convertible preferred stock in HCN in exchange of 100% of the holder’s preferred stock in HCN. At date of closing the 8,396,667 shares of common stock issued had a market valuation of $64,990,200 (based on market close of $7.74 on December 9, 2013) and the preferred stock issued had a value of $3,275,200 (8,188 shares at par value of $400).

In addition, the HCN 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.

In anticipation of the HCN Acquisition, HEC issued 619,960 shares of its common stock to HCN as full payment for HEC’s indebtedness to HCN in the amount of $3,589,567.  A condition to the Agreement closing was that HCN would sell the 619,960 shares before closing of the acquisition, which it did (see Note 10 – Capital Stock – Receivables for Common Stock).

With HCN, we acquired its 100% owned subsidiaries: Hydrocarb Namibia Energy (Pty) Limited, a Namibia Company and Hydrocarb Texas Corporation, a Texas Corporation; and its 95% owned subsidiary Otaiba Hydrocarb LLC, a UAE Limited Liability Company.

Prior to the HCN Acquisition, HCN was directly and indirectly majority-owned and controlled by HEC’s Chairman of the Board and entities related to him and his family.  Since HEC and HCN were under common control of a controlling party both before and after the completion of the share exchange, the transaction was accounted for as a business acquired from an entity under common control and the assets and liabilities acquired were recorded at HCN’s historical cost at Acquisition Date following ASC 805-50-30, Business Combinations.  Under this accounting treatment, the results of operations for the year ended July 31, 2014 and assets and liabilities of HCN are included in these financial statements as if the transaction had occurred at the beginning of the reporting period.  Prior reporting periods in these financial statements have been retroactively adjusted to include HCN and its subsidiaries.

According to ASC 805-50-30, the net assets of HCN are to be recorded at historical cost, therefore, the value of the 8,396,667 common shares and 8,188 preferred shares are deemed to be the same as the historical value of HCN net assets of $1,398,127 with excess of $599,409 recorded as additional paid in capital by HEC.

Summary of the accounting entry to record this acquisition in December 2013 is as follows:

Assets acquired	$	1,529,246
Liabilities assumed		(161,599	)
Noncontrolling interest in 95% owned HCN subsidiary		30,480
	$	1,398,127
Series A 7% Preferred Stock, par $400	$	3,275,200
Common stock, at par		8,397
Receivable for common stock		(2,484,879	)
Additional paid-in capital		599,409
	$	1,398,127

54

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

HCN had 51% working-interest rights in and operated an unevaluated onshore petroleum Namibian concession measuring approximately 5.3 million acres and covered by Petroleum Exploration License No. 0038 as issued by the Republic of Namibia Ministry of Mines and Energy. (“Namibian Concession”) described in Note 5 – Oil and Gas Properties, below, and provided international oilfield consulting services.  Prior to this acquisition, HEC owned a 39% working-interest right in this concession see NEI Acquisition below).  With the HCN acquisition, we now own a 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.

Namibia Exploration, Inc. (“NEI”) Acquisition

On August 7, 2012, we entered into a Share Exchange Agreement (the “NEI Agreement”), which was closed on September 6, 2012, under which we purchased NEI, a corporation organized under the laws of the state of Nevada for the issuance of 8,396,667 shares of our common stock as described below (the “NEI Acquisition”).  Prior to the acquisition, NEI was directly and indirectly owned and controlled by HEC’s then-Chief Executive Officer, his brother-in-law, and his father-in-law.

NEI was formed in February 2012 and its sole asset was a 39% working interest (43.33% cost responsibility) in the Namibian Concession. With the acquisition of HCN, the Company now has a 90% working interest (100% cost responsibility) in the Namibian Concession.  HEC now holds working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. ("NPC Namibia").

As NEI had no operations other than the ownership of the Namibian Concession, the transaction was accounted for as an asset purchase from an entity under common control and the asset was recorded at NEI’s historical cost of $562,048 with additional amounts paid considered compensatory and thus an expense of the acquisition.  The consideration included stock granted at the closing of the transaction as well as a series of stock grants that were contingent upon the achievement of certain market conditions.   The value of the total consideration, including contingent stock and the liabilities assumed in excess of NEI’s assets, was computed as described below.  $34,834,752 was reflected in our statement of operations as Acquisition-related costs – related party in conjunction with this transaction.

NEI originally acquired its interests in the Namibian Concession from Hydrocarb Namibia (a subsidiary of HCN) in exchange for a farm-in fee, totaling $2,400,000, payable over two years. At that time HCN was partly owned by the uncle of HEC’s then-Chief Executive Officer’s wife and brother-in-law.  Because the $2,400,000 fee was a related party transaction, and accordingly presumed not to be arms-length, and because there was substantial uncertainty about the realizability of the fees paid to HCN given that the concession was unproved, management concluded that HCN’s historical expenditures of $562,048 (which consists primarily of fees paid to the Namibian government for the concession) represented the fair value of the asset and NEI’s cost basis in the asset. The farm-in agreement also provided for preferential offerings of other international oil and gas opportunities similar to the concession in Namibia.  With the Company’s acquisition of HCN and its accounting for the HCN transaction as the acquisition of a business from an entity under common control, the $2,400,000 fee has been eliminated in consolidation, since these financial statements have been retroactively adjusted to include HCN and its subsidiaries since the beginning of the reporting period herein.

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HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Consideration for the acquisition of NEI

Pursuant to the terms of the Agreement, HEC issued 830,000 shares of common stock in September 2012 at the closing.  An additional 2,490,000 shares were contingently issuable as consideration for the NEI Acquisition, in accordance with the following milestones which were to have been reached within 10 years after the closing of the acquisition:

● a further 830,000 of the Shares will be issued when and if HEC's 10-day volume-weighted average market capitalization reaches $82,000,000;

● a further 2,490,000 of the Shares will be issued when and if HEC's 10-day volume-weighted average market capitalization reaches $196,000,000; and

● a further and final 4,150,000 of the Shares will be issued when and if HEC's 10-day volume-weighted average market capitalization reaches $434,000,000.

NEI’s cost basis in the Namibia Concession was $562,048.   The assets and liabilities were recorded at NEI’s carrying value on the date of the acquisition and the excess purchase price over the net assets acquired was recorded as an acquisition-related expense (compensation) because this was a related party transaction.   The purchase price consisted of the 830,000 shares that were awarded at closing, which were valued using the closing market price of the stock on the date of grant, and the 7,470,000 shares of the contingent stock grant.  The fair value of contingent stock grant was valued in accordance with ASC 820 – Fair Value Measurements.  The determination of fair value used a market approach weighted at 75% and the income approach (discounted cash flows) weighted at 25%.  The computations included consideration of projections of the future results of HEC and NEI, using multiple probability-weighted scenarios, and projections of HEC’s capital structure.  As of July 31, 2013, we had recognized $34,834,752 of expense associated with the acquisition of NEI, which consisted of the assumption of NEI’s net liability of $1,837,952, $3,784,800 associated with the 2,490,000 shares issued at the closing date of the acquisition and $29,212,000 associated with the contingent consideration.

In conjunction with the HCN acquisition in December 2013, the HEC Board of Directors authorized the immediate issuance of these contingently issuable 7,470,000 shares of our common stock to the former owners of NEI.  We issued these shares on December 9, 2013.

Hydrocarb agreement

In conjunction with the execution of the NEI Agreement, and as a condition of Closing, HEC entered into a Consulting Services Agreement with HCN (the "Consulting Agreement"), whereby HCN would provide various consulting services with respect to HEC's business ventures in Namibia and whereby HCN acknowledged and agreed that the obligations of NEI under its existing Farmin Opportunity Report with HCN (the "FOR") would be satisfied in exchange for HEC paying a consulting fee (the "Fee") to HCN of $2,400,000.  As a result of HEC’s acquisition of HCN, this Consulting Agreement and its related income/expense and receivable/payable have been eliminated in consolidation.

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HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3 – Supplemental Cash Flow Information

As of and For the year ended July 31,	2014			2013
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Income taxes	$	10,000		$	42,483
Interest	$	21,497		$	207,269
NONCASH INVESTING AND FINANCING ACTIVITIES
Issuance of HEC common stock to setle notes payable	$	3,589,567		$	-
Preferred stock exchanged for HCN preferred stock for acquisition of HCN	$	3,275,200		$	-
Receivable for common stock	$	1,859,879		$	-
Settlement of HCN debt with HCN preferred stock	$	1,585,200		$	1,690,000
Receivable for common stock - related party	$	1,000,000		$	-
Note payable for prepaid insurance	$	403,104		$	260,905
Asset retirement obligation sold	$	33,195		$	438
Common stock exchanged for HCN common stock for acquisition of HCN	$	8,397		$	-
Common stock issued to satisfy contingently issuable shares from 2012 acquisition of Namibia Exploration , Inc.	$	7,470		$	-
Asset retirement obligations - change in estimate	$	(104,237	)	$	786,120
Treasury stock acquired via note receivable	$	-		$	822,250
Acquisition of Namibia Exploration, Inc.	$	-		$	562,048
Expiration of derivative warrant liability	$	-		$	269,164
Accounts payable for oil and gas properties	$	-		$	188,607
Asset retirement obligations incurred	$	-		$	26,500

Note 4 – Available for Sale Securities

During the year ended July 31, 2012, we purchased securities at a market price of $702,959 and reclassified $6,383 unrealized loss from other comprehensive loss into earnings.

During September 2012, we received cash proceeds of $145,237 from sales of securities with a cost basis of $607,201; thus, we had a realized loss on sale of available for sale securities of $461,964. In October 2012, we recognized an other than temporary impairment of $275,327 resulting in a new cost basis in the stock of $174,000.

During December 2012, we received cash proceeds of $142,637 from sales of securities with a cost basis of $198,593; thus, we had a realized loss on sale of available for sale securities of $55,956. We reclassified $743,082 unrealized loss from other comprehensive loss into earnings in conjunction with these sales and the impairment.

As of July 31, 2014 and July 31, 2013, we do not hold any available for sale securities.

Note 5 – Oil and Gas Properties

Oil and natural gas properties consisted of the following:

For the year ended July 31,	2014			2013
Evaluated Properties
Costs subject to depletion	$	19,153,125		$	19,857,842
Accumulated impairment		(373,335	)		(373,335	)
Accumulated depletion		(3,491,420	)		(2,617,478	)
Total evaluated properties		15,288,370			16,867,029
Unevaluated properties		2,119,769			1,124,805
Net oil and gas properties	$	17,408,139		$	17,991,834

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HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Evaluated properties

Additions to evaluated oil and gas properties during the year ended July 31, 2014 and 2013 consisted mainly of exploration costs, geological and geophysical costs of $34,029 and $157,818, respectively.

Effective September 1, 2013, we conveyed our interest in the Dix, Melody, Curlee, Palacios and Illinois properties to Carter E&P, LLC in conjunction with our termination of Steven Carter as Vice President of Operations for $0 cash proceeds and the assumption of the abandonment liabilities of $4,381. In accordance with full cost rules, we recognized no gain or loss on the sale.

Effective March 25, 2014, we conveyed our interest in the Barge Canal Welder properties to Winright Oil Company, LLC.  We received net proceeds of $625,000 for this conveyance.  In accordance with full cost rules, we recognized no gain or loss on the sale.

Unevaluated Properties

Namibia, Africa

In September 2012, we acquired a 39% (43.33% cost responsibility) working interest in a concession in Namibia, Africa.  In September 2012, we acquired a 39% (43.33% cost responsibility) working interest in a concession in Namibia, Africa. With our acquisition of HCN in December 2013, we acquired an additional 51% (56.67% cost responsibility) and we now own 90% (100% cost responsibility) of this concession, as described above in Note 2 –Acquisitions.  This property is a 5.3 million-acre concession in northern Namibia in Africa.

For the year ended July 31, 2014 we have incurred total costs of $994,964, including NEI’s cost basis incurred upon acquisition of the property, which was $562,048.  For the year ended July 31, 2013 we incurred total costs of $1,124,805, including NEI’s cost basis incurred upon acquisition of the property, which was $562,048. 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 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.

As of July 31, 2014, approximately $2.1 million has been expended towards the initial exploration period.  As of July 31, 2013, approximately $900,000 has been expended towards the initial exploration period.

Additions to unevaluated properties for the year ended July 31, 2014 consisted primarily of:

(1) Approximately $800,000 of exploration costs associated with the acquisition of aerial gravity and magnetic data over the Namibia concession, and

(2) Approximately $129,000 of leasehold costs, specifically payment of the annual concession fee to the Government of Namibia.

58

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Offshore property

Our subsidiary, GBE, has interests in multiple leases with the State of Texas General Land Office in Galveston Bay. Through GBE, our primary operations are offshore in Galveston Bay. Significant changes to our offshore assets in Galveston Bay during the year ended July 31, 2014 include:

● Cost for a recompletion of Fisher Reef 2-3A#1;

● Cost for plugging/abandonment of two onshore wells;

● Costs for workover of Point Barrow salt water disposal well #1;

● Infrastructure enhancements; and

● Increase in asset retirement obligations primarily due to changes in timing and in estimated costs for the gathering systems located in Galveston Bay.

Sales of properties

In September 2012, we sold our 6.25% overriding royalty interests in properties located in Franklin and Richard parishes in Louisiana, the “Holt” and “Strahan” properties, to the operator of the properties and released the operator from any further liability from the note receivable in exchange for $50,000 cash.  We allocated the cash proceeds between an outstanding, and fully reserved, note receivable we held on the property and the overriding royalty interests based on the relative fair value of the balance on the note and the projected present value of the income streams from the royalty interests.  The portion attributable to the overriding royalty interest, $32,146, was treated as a reduction of capitalized costs in accordance with rules governing full cost companies.

In December 2012, we sold our 3% working interest in the producing Janssen lease located in Karnes County, Texas. We received $2,500 as cash proceeds in conjunction with the sale. The buyer assumed the asset retirement obligation for the well, which was $438. In accordance with full cost rules, we recognized no gain or loss on the sale.

Effective September 1, 2013, we conveyed our full interest in the Illinois, Palacios, Curlee, Dix, and Melody properties to Carter E&P in conjunction with our termination of Steven Carter as Vice President of Operations for $0 cash proceeds and the assumption of the abandonment liabilities.

Effective March 25, 2014, we conveyed our interest in the Barge Canal Welder properties to Winright Oil Company, LLC.  We received net proceeds of $625,000 for this conveyance.  In accordance with full cost rules, we recognized no gain or loss on the sale.

Note 6 - Impairment

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 July 31, 2014 and July 31, 2013, 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 7 – Asset Retirement Obligation

The following is a reconciliation of our asset retirement obligation liability as of July 31, 2014 and 2013, respectively.

59

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2014			2013
czReconciliation of asset retirement obligation balance
Liability for asset retirement obligation, beginning of period	$	10,933,398		$	9,382,933
Asset retirement obligations sold		(33,195	)		(438	)
Asset retirement obligations incurred on properties drilled		-			26,500
Accretion		1,043,928			1,056,508
Revisions in estimated cash flows		(104,237	)		786,120
Costs incurred		(123,664	)		(318,225	)
Liability for asset retirement obligation, end of period	$	11,716,230		$	10,933,398
Current portion of asset retirement obligation	$	1,133,690		$	724,374
Noncurrent portion of asset retirement obligation		10,582,540			10,209,024
Total liability for asset retirement obligation	$	11,716,230		$	10,933,398

Estimated Timing of asset retirement obligation payments:

Fiscal Year	Pipelines		Easements		Wellbores		Facilities		Total
2015	$	126,290	$	-	$	997,400	$	10,000	$	1,133,690
2016	$	60,000	$	27,516	$	639,725	$	-	$	727,241
2017	$	99,938	$	66,006	$	191,476	$	837,436	$	1,194,856
2018	$	55,040	$	14,475	$	548,700	$	-	$	618,215
2019	$	52,621	$	10,429	$	572,337	$	221,757	$	857,144
2020 to 2024	$	980,713	$	193,283	$	2,269,781	$	848,211	$	4,291,988
2025 to 2029	$	236,898	$	67,089	$	1,356,391	$		$	1,660,378
2030 to 2034	$	44,439	$	145,197	$	143,578	$	899,504	$	1,232,718
Thereafter	$	-	$	-	$	-	$	-	$	-
Total	$	1,655,939	$	523,995	$	6,719,388	$	2,816,908	$	11,716,230

The above dismantlement, restoration or abandonment obligations relate to the Company's following properties: (1) a combined total of 45 pipelines located in Chambers County, Texas and Galveston County, Texas (2) a combined total of 135 surface or right of way easements located in Chambers County. Texas and Galveston County, Texas (3) a combined total of 143 wellbores located in Chambers County, Texas and Galveston County, Texas and (4) a combined total of 8 facilities located in Chambers County, Texas and Galveston County, Texas.

The Company's ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company's oil and gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

As of July 31, 2014, the Company does not have any active dismantlement, restoration or abandonment activities in progress or underway. During the year ended July 31, 2014, the Company plugged 3 wells reducing its wellbore retirement obligations from those previously reported for the year ended July 31, 2013. The Company historically conducts all such remediation activities during the winter or spring periods, which have yet to be determined as of the date of this filing.

Note 8 – Notes Payable

Line of Credit

On March 17, 2011, GBE secured a one year revolving line of credit of up to $5 million with a commercial bank. The note specified interest at a rate of prime + 1% with a minimum interest rate of 5% per annum. The initial interest rate was 6%, and interest is payable monthly. Proceeds from the line of credit were used solely to enhance our Galveston Bay properties.  The note was collateralized by our Galveston Bay properties and substantially all of GBE’s assets. HEC also executed a parental guarantee of payment. The note was extended several times during fiscal 2013 and finally replaced by a term loan note in June 2013.  We held no balance outstanding on our line of credit for the years ended July 31, 2014 and July 31, 2013, respectively.  During the year ended July 31, 2014, we closed our LOC with the commercial bank and replaced it with an installment note payable.  See below for further details.

HCN Note Payable

During September 2012, in conjunction with the acquisition of NEI, HEC entered into a Consulting Services Agreement with HCN (the "Consulting Agreement”) which obligated HEC to pay a consulting fee (the "Fee") to HCN of $2,400,000 as follows:

(a) $800,000 on September 6, 2012, which was 15 days from the date that the Minister of Mines and Energy consented to the assignment of a 39% working interest in the Namibian concession to HEC, and

(b) $1,600,000 note payable, with principal payments of $800,000 each due on August 7, 2013 and August 7, 2014.

Interest accrued on the principal amount at the rate of 5% per annum, calculated semi-annually and payable in arrears. At HEC’s sole discretion, it could pay the first tranche of the Fee and principal associated with the note payable using HEC common stock. HEC was required to pay a late fee of 10% per quarter for any outstanding balance of the Fee under the Consulting Agreement which  commenced 30 calendar days from the date that the Fee or portion of the Fee is due, which by the terms of the Consulting Agreement may only be paid in cash.  The Consulting Agreement is more fully described in our audited financial statements for the year ended July 31, 2013, contained in our Annual Report filed with the SEC on Form 10-K.

In October 2013, prior to our acquisition of HCN, HEC settled the then-outstanding $2,400,000 Fee and $553,630 of interest and late fees associated with the Fee by issuance of HEC common stock (See Note 7 - Capital Stock). Further, $25,000 of the related interest and fees was settled in cash.  As the acquisition of HCN is accounted for as an acquisition of an entity under common control and prior reporting periods in these financial statements have been appropriately adjusted as if the acquisition had occurred at the beginning of the comparative periods, this note and related amounts have been removed from these financial statements.

Installment Notes Payable

In May 2012, we entered into a note payable of $18,375 to purchase a 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 $5,530 and $11,678 as of July 31, 2014 and July 31, 2013, respectively.

60

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In March 2013, we financed our commercial insurance program using a note payable for $260,905. Under the note, we were obligated to make nine payments of $29,591 per month, which include principal and interest, beginning in March 2013. The principal balance owed on the note payable as of July 31, 2013, was $115,958.  No amounts were owed on the note payable as of July 31, 2014.

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 July 31, 2014, the note payable balance was $179,158.

As noted above, in June 2013, the outstanding balance on our line of credit of $300,000 was replaced by a term loan that matures on June 22, 2015. Under the term loan, we are obligated to make twenty four monthly payments of $12,500 representing principal reduction plus interest per month. The note accrues annual interest at prime + 1%, currently totaling 6%.  As of July 31, 2014 and July 31, 2013, the balance outstanding related to this note was $150,000 and $275,000, respectively.  The July 2014 payment of $12,500 was not made and as a result, the Company incurred $663 in late fees and interest.  In August 2014, the Company paid off the outstanding balance of $150,000 plus accrued interest and fees, in connection with entering into the Credit Agreement with Shadow Tree Capital Management (see Note 15 - Subsequent Events, below).

Maturities of our long term debt obligation at July 31, 2014 are as follows:

Year ending July 31,	2015		Thereafter		Total
Operating and capital leases	$	-	$	-	$	-
Notes payable		334,688		-		334,688
Total	$	334,688	$	-	$	334,688

Note 9 – Fair Value

Fair value is defined as the amount that would be received for selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company categorizes financial assets and liabilities into the three levels of the fair value hierarchy. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value and bases categorization within the hierarchy on the lowest level of input that is available and significant to the fair value measurement.

● Level 1 — Quoted prices in active markets for identical assets or liabilities;

● Level 2 — Observable inputs other than Level 1, such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; and

● Level 3 — Significant unobservable inputs that are supported by little or no market activity or that are based on the reporting entity’s assumptions about the inputs.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

At July 31, 2014 and 2013 we had no financial assets and liabilities requiring measurement at fair value on a recurring basis.  We had no transfers in or out of either Level 1 or Level 2 fair value measurements during the years ended July 31, 2014 and 2013. During the annual 2013 period, we did recognize changes in the fair value measurement of our Level 3 derivative warrant liability during the years ended July 31, 2013.  No fair value measurement Level 3 derivative warrant liabilities existed during the year ended July 31, 2014.

Derivative Warrant Liabilities

Warrants – Third Party

During the year ended July 31, 2010 we issued certain warrants which contained a down-ratchet provision on the exercise price of the warrants.  In accordance with accounting guidance we utilize FASB ASC Topic No. 815-40 to determine whether an instrument (or embedded feature) is indexed to an entity’s own stock. This literature specifies when a contract would otherwise meet the definition of a derivative but that both (a) indexed to our stock and (b) classified in stockholders’ equity in our statement of financial position, would not be considered a derivative financial instrument.  The guidance provides a two-step model to be applied in determining whether a financial instrument or embedded feature is indexed to an issuer’s own stock and thus able to qualify for the scope exception.

61

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Based upon this guidance the warrants issued during the year ended July 31, 2010 were not afforded equity treatment due to the down-ratchet provision on the exercise price.  As a result, the warrants were not considered indexed to our own stock, and as such, the fair value of the embedded derivative liability was reflected on the balance sheet and all future changes in the fair value of these warrants were recognized currently in earnings in our consolidated statement of operations under the caption “Gain (loss) on warrant derivative liability” until such time as the warrants are exercised or the down-ratchet provision expires.

The warrants were fair valued using a multi-nominal lattice model with the following assumptions:

● The stock price on the valuation date would fluctuate with our projected volatility;

● Warrant holders would exercise at target price multiples of the market price trigger prices.  The target price multiple reduces as the warrants approach maturity;

● Warrant holders would exercise the warrant at maturity if the stock price was above two times the reset exercise price;

● An annual reset event would occur at 65% discount to market price; and

● The projected volatility was based on historical volatility.  Because we did not have sufficient trading history to determine our own historical volatility, we used the volatility of a group of comparable companies combined with our own historical volatility from May 2009, when we began trading.

The unrealized gain on changes in fair value was recorded as a reduction of the derivative liability and as an unrealized gain on the change in fair value of the liability in our statement of operations.  The warrant agreement provides that the antidilution provisions expire three years after the grant of the warrants.  Accordingly, the provision for warrants to purchase 206,400 shares of commons stock expired on November 13, 2012 and the warrants were determined to no longer be derivatives.  The outstanding warrant liability, as a result, was reclassified to additional-paid-in-capital and the fair value was determined for a final mark-to-market adjustment.

The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability as follows:

As of July 31,	2014		2013
Beginning of period	$	-	$	1,325,388
Expiration of derivative warrant feature		-		(269,164	)
Unrealized gain on changes in fair value of derivative liability		-		(1,056,224	)
End of period	$	-	$	-

Warrants – 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 as described in Note 11 – Related Party Transactions. 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, warrants to purchase 200,000 shares with an exercise price of $7.50 per share 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, warrants to purchase 200,000 shares 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.  As of July 31, 2014, the expense for the warrants was fully amortized.

62

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In accordance with accounting guidance, the fair value of the warrants that vest upon the attainment of a market condition is expensed and amortized over the lower of the implicit or derived service period of the warrants.  Any previously recognized expense is not reversed in the event of a subsequent decline in the fair value of market condition equity based compensation. During the year ended July 31, 2013, $1,056,224 of unrealized non-cash gains were recognized as fair value adjustments within Level 3 of the fair value measurement hierarchy and were recorded as a reduction of the derivative warrant liability and an unrealized gain on the change in fair value of the liability in our statement of operations. (See Note 10 – Capital Stock, for further details surrounding our warrant liability.

Note 10 – Capital Stock

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

	Warrant B			Warrant C
Fair Value		$	266,017		$	206,245

The following table reflects information regarding Warrant B and Warrant C during the year ended July 31, 2014 and 2013.

	July 31, 2014			July 31, 2013
	Warrant B			Warrant C
Compensation Expense recognized		$	6,754		$	196,384

Stock Split

Effective on May 8, 2014, we affected a 1:3 reverse split of our authorized common stock and a corresponding 1:3 reverse split of our outstanding common stock.  All share and per share amounts for all periods in this report have been retroactively restated to reflect the reverse split.

Effective November 29, 2013, the Company increased the number of its authorized shares of common stock from 166,666,667 shares, par value $0.001 per share to 333,333,334 authorized common shares with a par value of $0.001 per share.

Our capitalization at July 31, 2014 was 333,333,334 authorized common shares with a par value of $0.001 per share.

Series A Preferred Stock

On December 2, 2013, we filed a Certificate of Designation that created a new class of stock: Series A 7% Convertible Voting Preferred Stock (“Series A Preferred”).  Up to 10,000 shares of Series A Preferred are authorized. The stock has a stated value of $400 per share, pays annual dividends at 7%, and is convertible into HEC common stock, at the holder’s option, at a conversion rate of $6.00 per share. The Series A Preferred is neither redeemable nor is it callable. Series A Preferred shareholders may vote their common stock equivalent voting power. We analyzed the Series A Preferred using the guidance contained in ASC 815-40, Derivatives and Hedging, and concluded that the instrument was indexed to our own stock and qualified to be included in stockholders’ equity.

In connection with the acquisition of HCN on December 9, 2013, HEC issued 8,188 shares of our Series A Preferred Stock to a former Preferred Stock shareholder of HCN, as described in Note 2 – Acquisitions, above.  The value of the preferred stock at issuance was $3,275,200 (8,188 shares at par value of $400).  These shares were recorded in equity at par of $3,275,200.  Because the Series A preferred stock is immediately convertible, the value of a beneficial conversion feature of $949,808 was immediately recognized as a dividend.  During the year ended July 31, 2014, the holder of the Series A Preferred Stock received dividends of $34,254.  As of July 31, 2014, additional dividends have not been accrued as liabilities since they were not declared by the Company.

Common Stock Issuances

During September 2012, we issued 2,830,000 shares of common stock to the owners of Namibia Exploration, Inc. (“NEI”) for the acquisition of NEI.  The shares were valued at $3,784,800, based on the quoted market price of our stock on the date of the acquisition. Additionally, $31,612,000 was recognized in conjunction with our commitment to issue additional stock if certain market conditions are achieved. (See Note 2 – Acquisitions – Namibia Exploration, Inc.)

On October 31, 2013, we issued 619,960 shares of common stock to HCN to settle the $2,400,000 Fee as described in Note 8 – Notes Payable, $553,630 of interest and late fees associated with the Fee, and $635,937 of joint interest billings payable to HCN for its work on the Namibian concession.  The shares were valued and recorded at $3,589,567, based on the value of the obligations settled.

In connection with the acquisition of HCN on December 9, 2013, we issued 8,396,667 shares of our common stock, as described in Note 2 – Acquisitions, above.  These common stock shares were recorded in equity at par of $8,397 partially offset by additional paid-in capital of $1,837, as described above in Note 2 – Acquisitions.

In conjunction with the HCN acquisition, we issued 7,470,000 shares of our common stock to the former owners of NEI.  These shares were contingently-issuable consideration for the acquisition of NEI and we valued them at $31,612,000 and recorded it as Acquisition-related costs - related party expense in September 2012.

63

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the year ended July 31, 2014, we issued 167,904 shares of common stock, to employees and directors for services performed.  In conjunction with the issuance of these shares we recognized $813,827 in compensation expense.

HCN Series A Preferred Stock

On December 3, 2013, before the HEC acquisition of HCN, HCN issued 3,963 shares of its Series A Preferred Stock to Kent Watts, HCN CEO, in order to cancel amounts owed to him for advances he made to the Company in the amount of $1,379,891 plus accrued interest and dividends owed to him of $205,309, totaling $1,585,200.  The HCN Series A Preferred Stock provided for cash dividends of 7% per year, payable in either cash or shares of stock, at the Company’s option.  During the year ended July 31, 2014, the HCN preferred stock accrued dividends of $39,230, which was satisfied through the issuance of the HCN preferred stock on December 3, 2013.  These 3,963 shares of preferred stock plus the previously outstanding 4,225 shares were exchanged for 8,188 shares HEC Series A Preferred Stock, as described above in the acquisition of HCN.

Receivables for Common Stock

On September 6, 2013, HCN sold 191,667 shares of HEC common stock to an employee of HCN in exchange for a note receivable in the amount of $1,000,000. This HCN employee is the nephew of our current CEO. 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 market or NYSE stock exchange. 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 market or stock exchange, we will receive up to $1,000,000, or the note can be paid earlier at the discretion of the other party. We collected $675,000 in cash on this note receivable through July 31, 2014.  At July 31, 2013, these shares were classified as treasury stock within equity at the cost HCN obtained them from outside entities for services performed following the consolidation of comparative periods for acquired entities under common control (See Note 2 –Acquisitions).  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 unrelated 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.

This note receivable was extended on August 4, 2014, for an extension fee of $50,000, payable in the future, with $750,000 due to be repaid by December 31, 2014, with the remaining balance to be repaid by March 31, 2015.  These repayment terms may be changed if the Company is successful in being up-listed to either the NYSE or NASDAQ.  If this occurs, the entire balance is due within 60 days after an up-listing occurs.

Stock Compensation Plans

As of July 31, 2014, HEC could grant up to 570,136 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.

A new 2013 Stock Incentive Plan (2013 Plan) was approved by the Board during February 2013. The 2013 Plan replaced our prior stock incentive plans. HEC may grant up to 883,333 shares of common stock under the 2013 Plan. The Plan is administered by the Board of Directors, which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.

64

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of each option is estimated using the Black-Scholes valuation model. Expected volatility is based solely on historical volatility because we do not have traded options. Prior to May 2009, the volatility was determined by referring to the average historical volatility of a peer group of public companies because we did not have sufficient trading history to determine our own historical volatility.  Beginning with computations after May 2009, when there was an active trading market for our stock, we have included our own historical volatility in determining the volatility used.  As of October 2013, we determined that 4.5 years of trading history was sufficient to determine historical volatility; accordingly valuations from October 2013 onwards will be performed without using a peer group.

The expected term calculation for stock options is based on the simplified method as described in the Securities and Exchange Commission Staff Accounting Bulletin number 107. We use this method because we do not have sufficient historical information on exercise patterns to develop a model for expected term. The risk-free interest rate is based on the U. S. Treasury yield in effect at the time of grant for an instrument with a maturity that is commensurate with the expected term of the stock options. The dividend yield rate of zero is based on the fact that we have never paid cash dividends on our common stock and we do not intend to pay cash dividends on our common stock.

Options granted to non-employees

We account for options granted to non-employees under the provisions of ASC 505-50 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 vesting date, which is presumed to be the date the performance is complete.

In February 2013, options to purchase an aggregate of 200,000 shares of common stock with an exercise price of $6.60 per share and a term of ten years were granted to our three independent directors.  The options vest at the rate of 20% of such options each six months over the first 30 months following the grant date. The fair value of the total option award on the date of grant was $1,196,589. The fair market value of this award was estimated using the Black-Sholes option pricing model.

In August 2013, 13,333 of the 200,000 options granted to our independent directors became vested and the remainder of the previously unamortized fair value of these options, $16,184, was recognized on the vesting date. The fair value was estimated using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 2.01%, a dividend yield of 0%, and a volatility factor of 144.01%.

In October 2013, the board accelerated the vesting of the remaining 53,333 options so that they became fully and immediately vested.  The fair value of the options on the date of vesting of $810,738 was recognized immediately as an expense. The fair value was estimated using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 2.09%, a dividend yield of 0%, and a volatility factor of 117.31%.

In addition, during October 2013, the final tranche of certain options that had originally been granted to non-employees in April 2011 vested, for which we recognized $60,622 in expense.

The following table provides information about options granted to non-employees under our stock incentive plans during the years ended as follows:

As of July 31,	2014		2013
Number of options granted		-		200,000
Compensation expense recognized	$	887,544	$	679,174
Weighted average exercise price of options granted		N/A	$	6.60

65

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table details the significant assumptions used to compute the fair market values of stock options granted or revalued during the years ended as follows:

As of July 31,		2014				2013
Risk-free interest rate	N/A		-	N/A	1.11%		-	2.00%
Dividend yield				0%				0%
Volatility factor	N/A		-	N/A	140.3%		-	144.0%
Expected life (in years)				N/A				6.5

Based on the fair value of the options as of July 31, 2014, there was no unrecognized compensation costs related to non-vested share based compensation arrangements granted to non-employees.

Options granted to employees

The following table provides information about options granted to employees under our stock incentive plans.

For the year end July 31,	2014			2013
Number of options granted			-			-
Compensation expense recognized		$	56,028		$	253,952
Weighted average exercise price of options granted			N/A			N/A

During the year ended July 31, 2011, options to purchase 86,667 shares of common stock with an exercise price of $7.50 per share and a term of ten years were granted to five employees.  The options vest at the rate of 20% of such option each six months over the first 30 months following the grant date. Because the grantees were employees, the awards are accounted for under the provisions of ASC 718.  Accordingly, they are measured at fair value on the date of grant and the expense associated with the grant will be amortized over the 30 month vesting period on a straight line basis.  As of July 31, 2014, we had no unamortized compensation expense associated with options granted to employees, as shares were either cancelled or accelerated as of July 31, 2014.

No options were granted to employees during the years ended July 31, 2014 or 2013.

Summary information regarding stock options issued and outstanding as follows:

	Options			Weighted average share price		Aggregate intrinsic value		Weighted average remaining contractual life (in years)
Outstanding at July 31, 2012	$	348,000		$	7.50		-		7.22
Granted		200,000			6.60
Exercised		-			-
Expired or forfeited		(36,000	)		7.50
Outstanding at July 31, 2013	$	512,000		$	6.81		-		7.98
Granted		-			-
Exercised		-			-
Expired or forfeited		(246,667	)		7.50
Outstanding at July 31, 2014	$	265,333		$	6.81		-		7.95
Exercisable at July 31, 2014	$	265,333		$	6.81		-		7.95

66

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Options outstanding and exercisable as of July 31, 2014 as follows:

Exercise Price		Outstanding Number of Shares		Remaining Life		Exercisable Number of Shares
$	6.60		200,000		8.54		200,000
$	7.50		53,333		6.73		53,333
$	7.50		4,000		4.81		4,000
$	7.50		8,000		2.93		8,000
			265,333				265,333

Summary information regarding nonvested stock options as of July 31, 2013 is as follows:

Exercise Price		Outstanding Number of Shares		Remaining Life		Exercisable Number of Shares
$	6.60		200,000		9.54		-
$	7.50		265,333		7.73		212,267
$	7.50		20,000		3.93		20,000
$	7.50		8,000		5.81		8,000
$	7.50		18,667	Less than 1 year			18,667
			512,000				258,934

Summary information regarding nonvested stock options as of July 31, 2014 is as follows:

	Number of shares			Weighted average grant date fair value
Nonvested at July 31, 2013		253,067		$	7.41
Granted		-		$	-
Vested		(6,400	)	$	7.50
Forfeited		(246,667	)	$	7.50
Nonvested at July 31, 2014		-		$	-

Warrants

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 the father-in-law of Jeremy Driver, a former Director and our former Chief Executive Officer and the brother of our current CEO. 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, warrants to purchase 200,000 shares 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, warrants to purchase 200,000 shares with an exercise price of $7.50 and an expiration date of February 15, 2016 shall be exercisable (“Warrant C”). See Note 9 – Fair Value, for details regarding the fair value measurement and fair value methodology related to these warrants.

67

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summary information regarding common stock warrants issued and outstanding as of July 31, 2014, is as follows:

	Warrants			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (in years)
Outstanding at year ended July 31, 2012		1,252,152		$	7.74	$	-		2.83
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(15,193	)		28.02		-		-
Outstanding at year ended July 31, 2013		1,236,959		$	7.50	$	-		1.87
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(152,375	)		7.50		-		-
Outstanding at year ended July 31, 2014		1,084,584		$	7.50	$	-		1.04

Warrants outstanding and exercisable as of July 31, 2014:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	7.50		666,667	2 years or less		666,667
$	7.50		349,117	1 year or less		349,117
$	7.50		68,800	1 year or less		68,800
			1,084,584			1,084,584

Warrants outstanding and exercisable as of July 31, 2013:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	7.50		666,667	3 years or less		266,667
$	7.50		417,919	2 years or less		417,919
$	7.50		152,373	1 year or less		152,373
			1,236,959			836,959

Note 11 – Related Party Transactions

During the year ended July 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 Barge Canal properties. Although he was not a related party after September 2013, we considered the transactions with his company during his tenure as an officer of Hydrocarb as related party transactions because they were not compensation or ordinary course of business, and because he was a related party at the time they occurred.

Revenues generated, lease operating costs, and contractual overhead charges, which are included in lease operating costs incurred from these properties, were as follows:

Year Ended July 31,	2013		2014
Revenue generated from Barge Canal properties	$	643,203	$	39,274
Lease operating cost incurred from Barge Canal properties	$	224,047	$	23,259
Overhead costs incurred	$	28,038	$	-
Outstanding accounts receivable at period end	$	91,967	$	-
Outstanding accounts payable at year end	$	-	$	-

68

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the quarter ended October 2012, we purchased NEI for up to  8,396,667 shares of Duma common stock, as described in Note 2 – Acquisitions – Namibia Exploration, Inc.

In February 2013, we sold a 2% working interest in a 366.85 acre tract of unevaluated property, the Dix prospect, in San Patricio County, Texas to Carter. Carter paid cash of $1,541, the proportional share of the land acquisition costs.

In August 2013, we closed our Corpus Christi office and terminated this officer.  In conjunction with the office closure and termination, we assumed operatorship of the Barge Canal properties effective September 1, 2013.  In addition, we conveyed multiple properties located in the South Texas and Illinois area to this officer for $0 cash consideration and assumption of the associated asset retirement obligations. (See Note 5– Oil and Gas Properties)

The father of the former Chief Financial Officer and a company controlled by the father-in-law of the former Chief Executive Officer and brother to the current CEO, each purchased a 5% working interest in the ST 9-12A #4 well.  As of July 31, 2014 and 2013, the company controlled by the father-in-law of the former Chief Executive Officer owed us $58,014 and  $84,806, respectively. We also had an advance outstanding from the father of the former Chief Financial Officer, which was reflected in the caption “Due to related parties”, of $0 and $15,046 for the year ended July 31, 2014 and 2013, respectively.

During 2011, we entered into a consulting contract with a company controlled by Michael Watts, the father-in-law of Jeremy Driver, our former Chief Executive Officer and a former Director and the brother of our current CEO, as detailed in Note 10 – Capital Stock.  We recognized expense of $196,384 from this contract during the year ended July 31, 2013.  The contract terminated in 2014 but was extended by the board of directors indefinitely with zero additional compensation.  $6,754 was recognized in the year ended July 31, 2014.

In September 2013, before the HEC acquisition of HCN, HCN sold 191,667 shares of HEC common stock to an HCN employee, our Chairman’s nephew, in exchange for a $1,000,000 note receivable. The company arranged the sales of these shares in anticipation of a possible business combination, in an effort to ensure that the shares would remain as part of public float and therefore continue to be properly included in calculations for exchange-listing criteria and provide a source of funding for company operations. It was anticipated that the purchaser of these shares would, at a subsequent date, sell the referenced shares and attain the ability to pay the receivable. We collected $675,000 on the referenced note receivable through April 30, 2014. Of that amount, $275,000 was derived from the sales of the referenced shares; $400,000 was derived from the proceeds of a loan made to the purchaser of the referenced shares by our Chairman.

In October 2013, prior to our acquisition of HCN, we settled our obligations to HCN under the HCN Consulting Agreement through the issuance of 619,960 shares of HEC. These obligations consisted of the then-outstanding $2,400,000 Fee and $533,630 of interest and late fees associated with the Fee. (See Note 10 – Capital Stock). Further, $25,000 of the related interest and fees was settled in cash. Prior to HEC’s acquisition of HCN, HCN sold these shares to an unrelated entity, in which Michael Watts has a minority interest, for a note receivable of $1,859,879. The company arranged the sales of these shares in anticipation of a possible business combination, in an effort to ensure that the shares would remain as part of public float and therefore continue to be properly included in calculations for exchange-listing criteria and provide a source of funding for company operations. It is anticipated that these shares will eventually be sold and the proceeds of their sales used to pay the receivable. As HCN is now our wholly-owned subsidiary, this receivable for the sale of HEC common stock is classified as receivable for common stock within equity. See discussion of this receivable in Note 10 – Capital Stock – Receivables for Common Stock. On August 8, 2014 our board of Directors resolved to extend this note receivable with the terms for $750,000 to be paid by December 31, 2014 and the balance by March 31, 2015.

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. Additonally, 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 July 31, 2014. Accrued interest is pavable 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.

69

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12- Income Taxes

Our net loss before income taxes totaled $(7,683,932) and $(37,595,653) for the years ended July 31, 2014 and 2013, respectively. We recognized an income tax benefit during the years ended July 31. 2014 and 2013 because the estimated tax liability for the respective previous years exceeded the actual tax liability.

The reconciliation of our income tax provision at the statutory rate to the reported income tax expense is as follows:

As of and For the Year ended July 31,	2014			2013
U.S statutory federal rate		35 00	%		35.00	%
State income tax rate		0.58	%		0.58	%
Equity-based compensation		(5.16	)%		(33.62	)%
Gain on derivative warrants		-	%		0.93	%
Gain on sale of securities		-	%		(0.33	)%
Other		(6.64	)%		(0.50	)%
Net operating loss		(23.70	)%		(1.75	)%
Effective statutory rate		0.08	%		0.31	%

Our deferred income taxes reflect the net tax effects of operating loss, tax credit carry forwards and temporary differences between carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which temporary differences representing net future deductible amounts become deductible.

Components of deferred tax assets as of July 31, 2014 and 2013 are as follows:

As of and For the Year ended July 31.	2014			2013
Stock based compensation	$	338,078		$	713,867
Property. including depreciable property		(3,122,873	)		(2,980,005	)
Asset retirement obligation		4,168,049			3,942,918
Net operating loss carry-forward		5,596,732			3,846,783
Other		20,860			42,368
		7,000,846			5,565,931
Valuation allowance for deferred tax assets		(7,000,846	)		(5,565.931	)
Total deferred tax assets	$	-		$	-

The valuation allowance is evaluated at the end of each year, considering positive and negative evidence about whether the deferred tax asset will be realized. At that time, the allowance will either be increased or reduced; reduction could result in the complete elimination of the allowance if positive evidence indicates that the value of the deferred tax assets is no longer impaired and the allowance is no longer required.

We have no positions for which it is reasonable that the total amounts of unrecognized tax benefits at July 31. 2014 will significantly increase or decrease within 12 months.

Generally, our income tax years 2010 through 2014 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas which are the jurisdictions where we have our principal operations. No material amounts of the unrecognized income tax benefits have been identified to date that would impact our effective income tax rate.

As of July 31, 2014, we had approximately $15,732,204 of U.S. federal and state net operating loss carry-forward (“NOLs”) available to offset future taxable income, which begins expiring in 2027, if not utilized. Future tax benefits that may arise as a result of these losses have not been recognized in these financial statements.  The deferred tax asset generated by the loss carry-forward has been fully reserved due to the uncertainty we will be able to realize the benefit from it.

In conjunction with the merger with HCN, we believe we incurred an ownership change within the meaning of Section 382 of the Internal Revenue Code. As a result, applicable federal and state tax law places an annual limitation on the amount of NOLs that may be used. As of the filig date of this report, we have not completed our Section 382 analysis in connection with the merger.

If we were to have taxable income in excess of the 382 Limitation following a Section 382 “ownership change,” we would not be able to offset tax on the excess income with the NOLs. Although any loss carryforwards not used as a result of any Section 382 Limitation would remain available to offset income in future years (again, subject to the Section 382 Limitation) until the NOLs expire, the “ownership change” could significantly defer the utilization of the loss carryforwards, accelerate payment of federal income tax and may cause some of the NOLs to expire unused.

70

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13 – Commitments and Contingencies

Contingencies

Legal

We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.

As of July 31, 2014, we were party to the following legal proceedings:

Cause No. 2011-37552; Strategic American Oil Corporation v. ERG Resources, LLC, et al.; In the 55th District Court, Harris County, Texas. The Company is a plaintiff in this suit. In this case, Company brought claims for injunctive relief, breach of contract and fraudulent inducement against the defendant regarding the purchase of Galveston Bay Energy, LLC from ERG. The Company intends to prosecute its claims and defenses vigorously. As of the date of filing of this report, the Company is no longer seeking injunctive relief. Additionally, the below listed case has been consolidated into this case since the subject matter of the below case is subsumed within the subject matter of this case. From this point forward, there will be only this one piece of litigation. The trial was held in October 2013. The judge ruled in favor of ERG and that Hydrocarb is liable to pay the charges in the below-mentioned case and a portion of ERG’s attorney fees. The Company is in the process of post-trial motions and no judgment has been entered as of this date.  As of July 31, 2013, the Company had accrued $232,974 for this cause.

Cause No. 2011-54428; ERG Resources, LLC v. Galveston Bay Energy, LLC, in the 125th Judicial District Court, Harris County, Texas. This case deals with the operating agreements for the processing of product by the entities owned by ERG. It is an action seeking payments of charges and expenses by ERG that are refuted by GBE. The Company intends to prosecute its claims and defenses vigorously. As indicated above, this case has been consolidated into the case listed above. As such, the claims in this case will be decided in cause No. 2011-37552, which was tried in October 2013.

Settlement negotiations on both of these matters have been concluded. Galveston Bay has paid $35,000 in cash and Hydrocarb Energy will issue $65,000 in common stock to settle. More than this amount has been accrued previously and no further adjustments will be made to our financial statements.

A state regulator has requested that we renew certain pipeline easements located in Galveston Bay. The easements in question were originally obtained by another company whose successor filed for bankruptcy protection.  Our subsidiary, Galveston Bay Energy, LLC purchased certain assets from the bankruptcy estate; however, based on the bankruptcy court’s order and the purchase and sale agreement, we believe the pipelines and easements in question were not included in assets purchased. The easements in question were scheduled to renew at various dates between 2012 and 2021.  Based on current posted rates, the cost of renewal of all of the easements would be approximately $400,000.  We have engaged legal counsel to dispute the regulator’s claim.  If we are obligated to renew these easements, they would be part of the asset retirement obligation that was acquired with our subsidiary, Galveston Bay Energy, LLC. As such, the potential liability for these easements is factored into the computation of the asset retirement obligation (See Note 7 – Asset Retirement Obligation) that is estimated using the guidance in ASC 410-20, Asset Retirement and Environmental Obligations.  On August 29, 2014, we filed a lawsuit in the state district court in Chambers County, Texas asking the Court to reform an assignment and assumption agreement in the property records of Chambers County.  The General Land Office has asserted claims against us under various miscellaneous easements, claiming we are obligated to either renew the easement or remove any pipeline laid in the easement.  We have disclaimed any obligations under these easements.

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.

There is soil contamination at a tank facility owned by GBE. Depending on the technique used to perform the remediation, we estimate the cost range to be between $150,000 and $900,000. We cannot determine a most likely scenario, thus we have recognized the lower end of the range. We have submitted a remediation plan to the appropriate authorities and have not yet received a response. For the year ended July 31, 2014 and July 31, 2013, $150,000 has been recognized and is included in the balance sheet caption “Accounts payable and accrued expenses.”

71

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Commitments

In March 2011, we executed a lease for office space in Houston, Texas.  The lease term was three years and we had an option to extend the lease for an additional three years.  Our scheduled rent was $6,406 per month plus common area maintenance cost for the first year, $6,673 plus common area maintenance cost for the second year, and $6,940 per month plus common area maintenance cost for the third year.  We did not extend this lease, but entered into a sublease arrangement with Greenshale LLC for office space in the same building.  During September 2013, we terminated our lease for office space in Corpus Christi, Texas.

In April 2012, we executed a Compression and Handling Agreement (the “PHA”) with another operator. Under the terms of the PHA, oil, natural gas, and salt water from one of our fields would be disposed of through the operator’s facility. Under the agreement, we are responsible for approximately a flat fee of $1,000 per month as a gauging fee, our pro-rata share of repairs at the facility, and compression, salt water disposal, and other charges based on the volumes disposed of through the facility.

Rent expense during the years ended July 31, 2014 and 2013 was $186,463 and $211,346, respectively. See Note 8 – Notes Payable for details regarding our commitments related to our future obligations.

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.

During the year ended July 31, 2014 and 2013 we prepaid the fees associated with the Greenbank letters of credit for the respective year interest upfront and amortized these fees on a straight-line basis over their respective annual periods. The following table reflects the prepaid balances as follows:

July 31,	2014			2013
Prepaid letter of credit feees	$	101,251		$	101,850
Amortization		(8,488	)		(8,488	)
Net prepaid letter of credit fees	$	92,763		$	93,362

Note 14 – Additional Financial Statement Information

Other receivables

Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate.  We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. As of July 31, 2014 and 2013, we have reserved $70,742 and $58,585, respectively, for potentially uncollectable other receivables.

72

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other current assets

Other current assets consisted of the following:

As of July July 31,	2014		2013
Prepaid letter of credit fees	$	92,763	$	93,362
Prepaid insurance		287,743		184,138
Other prepaid expenses		63,143		11,101
Cash call paid to operator		-		24,225
Prepaid land use fees		-		28,728
Accrued interest income		2,671		4,388
Other current assets	$	446,320	$	345,942

Property and Equipment

Property and equipment consisted of the following:

As of July 31,		2014			2013
Furniture and fixtures	5 years	$	24,085		$	8,814
Marine vessels	5 years		109,742			17,614
Vehicles	5 years		40,496			65,807
Computer equipment and software	2 years		126,143			82,466
Leasehold improvements	2 years		2,087			-
Other depreciable property	2 years		-			297
Total property and equipment			302,553			174,998
Less accumulated depreciation			(135,590	)		(116,945	)
Net book value		$	166,963		$	58,053
Depreciation expense		$	36,894		$	61,215

Accounts payable and accrued expenses

Accounts payable and accrued expenses consisted of the following:

As of July 31,	2014		2013
Trade payables	$	2,567,324	$	2,503,820
Accrued payroll		43,578		151,577
Accrued interest and fees		37,853		500
Revenue payable		5,790		4,717
Local taxes and royalty payable		111,699		128,470
Federal and state income taxes payable		29,431		27,000
Total accounts payable and accrued expenses	$	2,795,675	$	2,816,084

Note 15 – Subsequent Events

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 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.

Effective November 6, 2014, settlement negotiations with respect to the ERG Resources lawsuit have been concluded. Galveston Bay Energy has paid $35,000 in cash and Hydrocarb Energy will issue 65,000 shares in restricted common stock to settle. More than this amount has been accrued previously and no further adjustments will be made to our financial statements.

73

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pursuant to the Credit Agreement, we have the right, at any time prior to the one year anniversary of the Credit Agreement, to borrow up to an additional $1,000,000 under the Credit Agreement (the “Additional Loan”), subject to certain pre-requisites and requirements as set forth in the Credit Agreement, including, but not limited to us raising $750,000 through the sale of equity subsequent to the closing of the transactions contemplated by the Credit Agreement (which we agreed to obtain within 150 days of the date of the Credit Agreement).  We also agreed to pay a 2% Structuring Fee on the Additional Loan. The proceeds of the Additional Loan may only be used for the Oil and Gas Activities.

The amount owed pursuant to the Notes (and any amount borrowed pursuant to the Additional Loan) is guaranteed by our wholly-owned subsidiary, Hydrocarb Corporation (“HC”) and its subsidiaries, and our other wholly-owned subsidiaries and is secured by a first priority security interest in substantially all of our assets (including, but not limited to the securities of our subsidiaries and HC and its subsidiaries) evidenced by a Guarantee and Collateral Agreement, various pledge agreements and a deed of trust providing the Agent, as agent for the Lenders, a security interest over our oil and gas assets and rights.

The Notes do not accrue any interest for the first nine months after their issuance date (August 15, 2014), provided thereafter they accrue interest at the rate of (a) 16% per annum where the average net monthly oil and gas production revenues of Galveston Bay Energy LLC, our wholly-owned subsidiary, for the trailing three month period (the “Trailing Three Month Revenues”) is less than $900,000; or (b) 14% per annum, where the Trailing Three Month Revenues are equal to or greater than $900,000, payable monthly in arrears through the maturity date of such Notes, August 15, 2016.  The Additional Loan, if any, will bear interest at the rate of 14% per annum, payable monthly in arrears, and will have the same maturity date as the Notes.  Upon the occurrence of an event of default, the Notes (and any amount outstanding under the Additional Loan) will bear interest at the rate of 24% per annum until paid in full.

Pursuant to the Credit Agreement, we agreed to issue the Lenders their pro rata share of (a) 60,000 restricted shares of common stock on the effective date of the Credit Agreement, August 15, 2014 (the “Effective Date”); (b) 32,500 restricted shares in the event any amount of the Loans (or other obligations outstanding under agreements entered into in connection with the Loans, the “Loan Documents”) are outstanding on the 12 month anniversary of the Effective Date; (c) 32,500 restricted shares in the event any amount is outstanding under the Loan Documents on the 18 month anniversary of the Effective Date; and (d) 25,000 restricted shares in the event any amount is outstanding under the Loan Documents on the 21 month anniversary of the Effective Date.  The shares are to be 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.

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.

The Credit Agreement includes customary events of default for facilities of a similar nature and size as the Credit Agreement, including, but not limited to, if any breach or default occurs under the Loan Documents, the failure of the Company to pay any amount when due under the Loan Documents, if the Company (or its subsidiaries) is subject to any judgment in excess of $250,000 which is not discharged or stayed within 30 days, or if a change in control of the Company, any subsidiary or any guarantor should occur, defined for purposes of the Credit Agreement as any transfer of 25% or more of the voting stock of such entity.

Subsequent to the issuance of the original Annual Report on Form 10-K, it was determined that our subsidiary, Otaiba Hydrocarb LLC in Abu Dhabi, United Arab Emirates, would be shut down. All expenses of operating have been realized on an ongoing basis, so the accounting effect of this shutdown is immaterial.

Note 16 – Supplemental Oil and Gas Information (Unaudited)

The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the SEC and ASC 932, Extractive Activities —Oil and Gas, (ASC 932).

74

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made. The oil price as of July 31, 2014 and 2014 is based on the 12-month un-weighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) posted price which equates to $100.11 and $92.52 per barrel, respectively. The gas price as of July 31, 2014 and 2013 is based on the 12-month un-weighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) spot price which equates to $4.10 and $3.51 per MMbtu, respectively. The base prices were adjusted for heating content, premiums and product differentials based on historical revenue statements. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States; specifically, primarily in on-shore and off-shore Texas.

The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers. Our proved reserves are located in the United States of America, our home country.

Proved Reserves

	Oil			Gas			Total
	(Barrels)			(Mcf)			(Mcfe)
Balance – July 31, 2012		1,388,250			14,737,960			23,067,460
Revisions of previous estimates		(667,307	)		(1,830,745	)		(5,834,587	)
Sale of reserves in place		(1	)		(2	)		(8	)
Production		(61,242	)		(176,823	)		(544,275	)
Balance – July 31, 2013		659,700			12,730,390			16,688,590
Revisions of previous estimates		422,261			4,477			2,538,043
Sale of reserves in place		(17,750	)		(529,937	)		(636,437	)
Production		(42,436	)		(173,569	)		(428,185	)
Balance – July 31, 2014		1,021,775			12,031,361			18,162,011

During the year ended July 31, 2013, the Company decreased estimated reserves reported under the line items “Revisions of previous estimates” due to the decrease of previously estimated reserves related to the wells located in the Fishers Reef field located in Galveston Bay, Texas. As a result, during the year ended July 31, 2013, the Company plugged and abandoned these wells. During the year ended July 31, 2014, the Company increased estimated reserves reported under the line items “Revisions of previous estimates” due to an increase in certain previously estimated reserves in the Galveston Bay, Texas properties. When we acquired Galveston Bay Energy LLC in 2011, the Company had over 100 well-bores that had been shut in and scheduled for potential plugging and abandonment. Since the date of the acquisition, our technical staff undertook a review of the old well logs and other technical data associated with such review to identify additional undeveloped oil reserves in these leases. All increases in proved undeveloped reserves are due to the re-evaluation of previously available technical data associated with such review. We have not obtained new technical data. We believe that the new interpretations and reevaluations better reflect the underlying technical data. For the year ended July 31, 2014, this increase related primarily to revaluations associated with the Trinity Bay Field.

Proved Reserves as of July 31, 2014	Oil (Barrels)		Gas (Mcf)		Total (Mcfe)
Proved developed producing		200,981		969,940		2,175,826
Proved developed non-producing		212,320		4,813,192		6,087,112
Proved undeveloped		608,474		6,248,229		9,899,073
Total proved reserves		1,021,775		12,031,361		18,162,011

75

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Oil		Gas		Total
Proved Reserves as of July 31, 2013	(Barrels)		(Mcf)		(Mcfe)
Proved developed producing		256,290		1,554,420		3,092,160
Proved developed non-producing		229,290		5,000,960		6,376,700
Proved undeveloped		174,120		6,175,010		7,219,730
Total proved reserves		659,700		12,730,390		16,688,590

Proved developed producing and proved developed non-producing reserves decreased from July 31, 2014 to July 31, 2013 as a result of changes in estimates, based on current information.  The increase in proved undeveloped reserves was a result of an increase in certain previously estimated reserves in the Galveston Bay, Texas property.

The reserves in the report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.

Capitalized Costs Related to Oil and Gas Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization.

For the year ended July 31,	2014			2013
Unevaluated properties	$	2,119,769		$	1,124,805
Evaluated properties		19,153,124			19,857,842
Less impairment		(373,335	)		(373,335	)
		20,899,558			20,609,312
Less depreciation, depletion, and amortization		(3,491,420	)		(2,617,478	)
Net capitalized cost	$	17,408,138		$	17,991,834

Costs Incurred in Oil and Gas Activities

Costs incurred in property acquisition, exploration and development activities for the year ended July 31, 2014 were as follows.

	Total			Namibia		USA
Property acquisition
Unproved	$	821,665		$	821,665	$	-
Proved		13			-		13
Exploration		238,112			173,299		64,813
Drilling and development costs		(6,334	)		-		(6,334	)
Changes in ARO		(105,015	)		-		(105,015	)
Cost recovery		(658,195	)		-		(658,195	)
Total costs incurred	$	290,246		$	994,964	$	(704,718	)

76

HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Costs incurred in property acquisition, exploration, and development activities for the year ended July 31, 2013 were all incurred in the USA.  The following table provides information about the costs incurred:

	Total			Namibia		USA
Property acquisition
Unproved	$	1,219,457		$	1,088,945	$	130,512
Proved		3,000			-		3,000
Exploration		404,265			35,860		368,405
Development		1,732,451			-		1,732,451
Cost recovery		(196,001	)		-		(196,001	)
Total costs incurred	$	3,163,172		$	1,124,805	$	2,038,367

Costs Excluded

Our excluded costs as of July 31, 2014 and 2013 relate to costs incurred in the concession acquired in Namibia, Africa. The concession provides for a multi-year exploration program as described in Note 4 – Oil and Gas Properties.  The program provides that an initial well be drilled by September 2017.  Accordingly, we anticipate including the excluded costs in the amortization base within the next four to five years.  All costs that were excluded as of July 31, 2014 and 2013 were as follows, and were incurred during the respective years noted below.

Costs Excluded by Year Incurred

As of July 31,	2014		2013
Property acquisition	$	821,665	$	1,088,945
Exploration		173,299		35,860
Total	$	994,964	$	1,124,805

Changes in Costs Excluded by Country

	Namibia		USA
Balance at July 31, 2012	$	-	$	265,639
Additional Cost Incurred		1,124,805		278,090
Cost recovery		-		(132,662	)
Costs Transferred to DD&A Pool		-		(411,067	)
Balance at July 31, 2013		1,124,805		-
Additional Cost Incurred		994,964		-
Balance at July 31, 2014	$	2,119,769	$	-

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flow information has been developed utilizing ASC 932, Extractive Activities —Oil and Gas, (ASC 932) procedures and based on estimated oil and natural gas reserve and production volumes. It can be used for some comparisons, but should not be the only method used to evaluate us or our performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of our current value.

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HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We believe that the following factors should be taken into account when reviewing the following information:

● future costs and selling prices will probably differ from those required to be used in these calculations;

● due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

● a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

● future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, the future cash inflows were estimated by applying the un-weighted 12-month average of the first day of the month cash price quotes, except for volumes subject to fixed price contracts, to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. The reserve report, as prepared by an independent consulting petroleum engineer and attached to the Form 10-K at Exhibit 99.1, filed for the years ended July 31, 2014 and 2013, respectively, did not include all future plugging and abandonment costs. Therefore, the Company made adjustments for these costs in its computations of the Standardized Measure.  All proved reserves are located in the United States of America.

The Standardized Measure is as follows:

For the year ended July 31,	2014			2013
Future cash inflows	$	159,283,690		$	113,603,450
Future production costs		(54,437,098	)		(55,897,070	)
Future development costs		(43,054,816	)		(41,794,284	)
Future income tax expenses		(21,627,122	)		(5,569,234	)
		40,164,654			10,342,862
10% annual discount for estimated timing of cash flows		(15,807,988	)		(3,990,069	)
Future net cash flows at end of year	$	24,356,666		$	6,352,793

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for our proved oil and natural gas reserves during each of the years in the two year period ended July 31, 2014:

	2014			2013
Standardized measure of discounted future net cash flows at beginning of year	$	6,352,793		$	33,663,886
Net changes in prices and production costs		20,980,014			(37,623,010	)
Changes in estimated future development costs		(764,412	)		4,205,045
Sales of oil and gas produced, net of production costs		(151,783	)		(2,510,339	)
Discoveries and extensions		-			-
Purchases of minerals in place		-			-
Sales of minerals in place		(2,228,023	)		(17	)
Revisions of previous quantity estimates		8,885,117			(12,391,911	)
Development costs incurred		-			1,124,107
Change in income taxes		(9,694,393	)		14,705,973
Accretion of discount		977,353			5,179,059
Standardized measure of discounted future net cash flows at year end	$	24,356,666		$	6,352,793

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HYDROCARB ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following schedule includes only the revenues from the production and sale of gas, oil, condensate and NGLs. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

Results of Operations for Producing Activities

For the year ended July 31,	2014			2013
Net revenues from production	$	5,065,096		$	7,070,540
Expenses
Lease operating expense		4,913,313			4,560,201
Accretion		1,043,928			1,056,508
Operating expenses		5,957,241			5,616,709
Depreciation, depletion and amortization		873,942			1,059,803
Total expenses		6,831,183			6,676,512
Income before income tax		(1,766,087	)		394,028
Income tax expense		-			(137,910	)
Results of operations	$	(1,766,087	)	$	256,118
Depreciation, depletion and amortization rate per net equivalent MCFE	$	2.04		$	1.95

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ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Principal Executive Officer and Principal Financial 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 and Principal Financial Officer have 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 below.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting.

As of July 31, 2014, we assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and SEC guidance on conducting such assessments. We utilized the original (1992) COSO Framework to conduct our assessment.  Based on that evaluation, we concluded that, as of July 31, 2014, our internal controls and procedures were not effective to detect the inappropriate application of accounting principles generally accepted in the United States of America as more fully described below. This was due to deficiencies that existed at the time in which the internal control procedures were implemented that adversely affected our internal controls and that may be considered to be a material weakness.

The matters involving internal controls and procedures that our management considered to be material weaknesses under the standards of the Public Company Accounting Oversight Board were: (1) while the Company has implemented written policies and procedures for accounting and financial reporting with respect to the requirements and application of US GAAP and SEC disclosure requirements, we have not conducted a formal assessment of whether the policies that have been implemented address the specific risks of misstatement; accordingly, we could not conclude whether the control activities are designed effectively nor whether they operate effectively; and (2) we do not have an effective mechanism for monitoring the system of internal controls.

Management believes that the material weaknesses set forth above did not have a material adverse effect on our financial results for the year ended July 31, 2014.

We are committed to improving our financial organization. Our control weaknesses are largely a function of not having sufficient staff.  As resources become available, we plan to augment our staff so that we can devote more effort to addressing our control deficiencies.  Additionally, as financial resources become available, we will consider engaging third party consultants to assist with control activities.

We will continue to monitor and evaluate the effectiveness of our internal controls and procedures over financial reporting on an ongoing basis and are committed to taking further action by implementing additional enhancements or improvements, or deploying additional human resources as may be deemed necessary.

Changes in Internal Control over Financial Reporting

During our fourth quarter of our fiscal year ended July 31, 2014, we implemented and documented entity-level controls, formalized risk assessment processes, and adopted additional policies and procedures that improved our internal control over financial reporting.

ITEM 9B.  OTHER INFORMATION

Not applicable.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Officers and Directors

Our directors and executive officers and their respective ages as of the date of this annual report are as follows:

Name	Age	Position with the Company
Kent P. Watts	56	Chief Executive Officer and Chairman
Charles F. Dommer	60	President and Chief Operating Officer
Christine P. Spencer	58	Chief Accounting Officer
S. Chris Herndon	54	Director

The following describes the business experience of each of our directors and executive officers, including other directorships

held in reporting companies:

Kent P. Watts, Chairman and a director

Mr. Watts was appointed to the board of directors and as Chairman on October 11, 2013. On August 8, 2014, the Board of Directors appointed Mr. Watts as Chief Executive Officer. Mr. Watts is currently and has been Chairman and Chief Executive Officer of Hydrocarb Corporation since November 2009. Between June 1997 and October 2009 he was the founder, Chairman, and Chief Executive Officer for Hyperdynamics Corporation (NYSE MKT:HDY), an exploration and production company and prior to that an information technology services company. In 2006 Mr. Watts became the Founder and Chairman of American Friends of Guinea (AFG), a non-profit organization. He remains Chairman of AFG. Prior to June 1997, Mr. Watts served as Chairman, President and Chief Executive Officer of several companies in varying fields such as information technology services and computer manufacturing.  From 1983 to 1987 Mr. Watts provided advisory and public accountancy and advisory services. He holds a BBA from the University of Houston and he is a licensed Certified Public Accountant and Real Estate Broker in the State of Texas.

Director Qualifications:

Mr. Watts has extensive experience in the oil and natural gas industry. As Chief Executive Officer of Hydrocarb, Mr. Watts has played a key role in the executive management and implementation of strategic initiatives at the Company. As such, we believe that Mr. Watts is qualified to serve as a director.

Charles F. Dommer, President and Chief Operating Officer

Charles F. Dommer was appointed President and Chief Operating Officer on October 27, 2013.  Mr. Dommer is an exploration and development executive with 35 years of managerial positions for international and domestic oil and gas exploitation, exploration and acquisitions.  Mr. Dommer has managed many major projects in the competitive arena of oil and gas exploration and development. From December 2010 until present, Mr. Dommer has served as the Vice President of Exploration and Development for Hydrocarb Corporation.  From January 2000 to December 2010, Mr. Dommer served as President for Trans Global Engineering, Inc., of Denver, Colorado, primarily directing production operations as Chief Geologist (Vice President of Exploration and Production) for Lukoil-AIK in Russia.  Mr. Dommer’s past experience includes Senior Geologist at Phillips Petroleum Company, located in Texas, and the establishment of a Geology and Reservoir Engineering Department in Siberia as Chief Geologist (Vice President of Exploration and Production) for Occidental Petroleum Joint Venture, Vanyoganneft.  Mr. Dommer has a B.S. Geology degree from Arizona State University.

Christine P. Spencer, Chief Accounting Officer

On June 13, 2014, Christine P. Spencer was appointed Chief Accounting Officer of the Company. Ms. Spencer has been the controller of Hydrocarb Energy Corp. since February of 2013.  During the previous five years, Ms. Spencer had the following experience: from October 2010 to July 2012, she was controller of Platinum Pressure Pumping, an oilfield service company; prior to that, from November 2009 to October 2010, she served as controller of Holden Roofing Company, a residential and commercial roofing company; and from April 2008 through August 2009, Ms. Spencer was the Chief Financial Officer for David Powers Homes, a residential building contractor.  Ms. Spencer is a certified public accountant in Texas and has over 37 years of public and private accounting experience.  Ms. Spencer has a Bachelors of Science in Accountancy, with High Honors from the University of Illinois.

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S. Chris Herndon, Director

Mr. Herndon has been a director since October 11, 2012.  Mr. Herndon is an experienced financial and management professional with more than 30 years of experience. Currently, Mr. Herndon serves as Partner of Cyrus Partners, an investment company focusing on the energy, healthcare, and real estate sectors. Beginning in 2002 through 2011, Mr. Herndon served as Chief Financial Officer and Partner of AppOne, a financial technology company designed to serve the auto finance industry. From 1996 to 2001, Mr. Herndon served as CEO and Partner of The Mattress Firm, growing the organization from 100 stores to 275 stores before selling the firm to Bain Capital. Mr. Herndon was also a Registered Investment Advisor with Malachi Financial Services from 1994 to 1996. From 1983 to 1994, Mr. Herndon served as Chief Financial Officer and Controller of Duer Wagner and Co., an oil and gas operator in Texas. From 1982 to 1983 he served as a Public Accountant with Price Waterhouse.

Mr. Herndon is a graduate of Texas Christian University where he earned his Bachelor of Business Administration and Accounting, after which he became a Certified Public Accountant (CPA) in 1985. He is actively involved with several charities locally and internationally.

Director Qualifications:

Mr. Herndon has extensive experience in the business world in general. He also has extensive practical knowledge of doing business in Texas and the United States. In addition, we believe Mr. Herndon demonstrates personal and professional integrity, ability, judgment, and effectiveness in serving the long-term interests of the Company’s shareholders.  As a result of the above, we believe that Mr. Herndon is qualified to serve as a director.

Term of Office

Our directors are appointed for a one-year term to hold office until the next annual general meeting of our stockholders or until they resign or are removed from the board in accordance with our bylaws. Our officers are appointed by our Board of Directors and hold office until they resign or are removed from office by the Board of Directors.

Significant Employees

Other than Craig Alexander, our Vice President, the Company has no significant employees other than our executive officers.  Mr. Alexander has been with the company since early 2011. Before joining our Company, he was employed by Galveston Bay Energy serving as Operations Manager. Mr. Alexander has more than 21 years of oil and gas experience in production and completion engineering and operations management with Erskine Energy, Millennium Offshore Group, and Amerada Hess Corporation. He is a graduate of the University of Texas at Austin with a B.S. in Petroleum Engineering.  Mr. Alexander is considered a non-executive officer.

Committees

Our board of directors has established three committees to assist in the governance of the Company, the Audit Committee, the Compensation Committee, and the Nomination Committee.  At the present time, the Company has only one independent director and will seek to add additional independent directors in the future and/or as required. The three committees will serve their functions at such future time.

Mr. Herndon is an “independent” director of the Company as that term is defined in Rule 121 of the NYSE MKT Equities Exchange listing standards.  The Board of Directors of the Company has determined that Mr. Herndon qualifies as an audit committee financial expert pursuant to SEC rules.

Family Relationships

As of July 31, 2014, there are no family relationships among our directors and officers.

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CORPORATE GOVERNANCE

The Company promotes accountability for adherence to honest and ethical conduct; endeavors to provide full, fair, accurate, timely and understandable disclosure in reports and documents that the Company files with the Securities and Exchange Commission (the “SEC”) and in other public communications made by the Company; and strives to be compliant with applicable governmental laws, rules and regulations.

Board Leadership Structure

Approximately two weeks prior to the July 18, 2014 meeting of the Company's Board of Directors, four of the five directors signed a Consent to reorganize the Company's management structure by appointing Pasquale Scaturro, Director of International Business and appointing Chairman Kent Watts as the new Chief Executive Officer. Pasquale Scaturro, Paul Schillmoller, S. Chris Herndon, and Kent Watts signed the Consent; Byrd Larberg did not. Prior to the Board meeting, Mr. Watts received information that two of the directors had planned to abandon the agreement set forth in the above-referenced consent and together with Mr. Larberg planned to seek the appointment of Mr. Larberg as Chairman. In response, Chairman Watts presented Consents from the majority of shareholders to amend the company by-laws and elect Mr. Watts as the Company's Executive Chairman. Upon presentation of the shareholder Consents at the July 18, 2014 directors meeting, Directors Larberg, Shillmoller and Scaturro resigned from the board. Their resignations were accepted at a board of directors meeting held the next day. At this meeting, acting solely as a shareholder. Chairman Watts rescinded his signature on the referenced shareholder consents. In a subsequent directors meeting, directors Kent Watts and S. Chris Herndon acted to amend the company by-laws and appoint Kent Watts as Executive Chairman, and subsequently Chief Executive Officer. The Company continues to seek additional qualified independent directors.

Our Board of Directors has the responsibility for selecting the appropriate leadership structure for the Company. In making leadership structure determinations, the Board of Directors considers many factors, including the specific needs of the business and what is in the best interests of the Company’s stockholders. Our current leadership structure is comprised of a combined Chairman of the Board and Chief Executive Officer (“CEO”), Mr. Watts. The Board of Directors believes that this leadership structure is the most effective and efficient for the Company at this time.  Mr. Watts possesses detailed and in-depth knowledge of the issues, opportunities, and challenges facing the Company, and is thus best positioned to develop agendas that ensure that the Board of Directors’ time and attention are focused on the most critical matters. Combining the Chairman of the Board and CEO roles promotes decisive leadership, fosters clear accountability and enhances the Company’s ability to communicate its message and strategy clearly and consistently to our stockholders, particularly during periods of turbulent economic and industry conditions.

Risk Oversight

Effective risk oversight is an important priority of the Board of Directors. Because risks are considered in virtually every business decision, the Board of Directors discusses risk throughout the year generally or in connection with specific proposed actions. The Board of Directors’ approach to risk oversight includes understanding the critical risks in the Company’s business and strategy, evaluating the Company’s risk management processes, allocating responsibilities for risk oversight among the full Board of Directors, and fostering an appropriate culture of integrity and compliance with legal responsibilities.

The Board of Directors exercises direct oversight of strategic risks to the Company. As discussed above, three committees have been established to assist with the governance of the Company.  The Audit Committee reviews and assesses the Company’s processes to manage business and financial risk and financial reporting risk. It also reviews the Company’s policies for risk assessment and assesses steps management has taken to control significant risks.  The Compensation Committee will oversee risks relating to compensation programs and policies.  In each case, management periodically reports to our Board or relevant committee, which provides guidance on risk assessment and mitigation. The Nominating Governance Committee will recommend the slate of director nominees for election to the Company’s Board of Directors, identify and recommend candidates to fill vacancies occurring between annual stockholder meetings, review, evaluate and recommend changes to the Company’s Corporate Governance Guidelines, and establish the process for conducting the review of the Chief Executive Officer’s performance.  The Company is currently searching for two additional independent directors to assist with these processes.

Arrangements between Officers and Directors

To our knowledge, there is no arrangement or understanding between any of our officers and any other person, including directors, pursuant to which the officer was selected to serve as an officer.

Other Directorships

No directors of the Company are also directors of issuers with a class of securities registered under Section 12 of the Exchange Act (or which otherwise are required to file periodic reports under the Exchange Act).

Involvement in Certain Legal Proceedings

None of our executive officers or directors has been involved in any of the following events during the past ten years:

(1) any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;

(2) any conviction in a criminal proceeding or being a named subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);

(3) being subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities;

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(4) being found by a court of competent jurisdiction (in a civil action), the SEC or the Commodities Futures Trading Commission to have violated a federal or state securities or commodities law;

(5) being the subject of, or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of (i) any Federal or State securities or commodities law or regulation; (ii) any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or (iii) any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or

(6) being the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

Board of Directors Meetings

The Company had 25 official meetings of the Board of Directors of the Company during the last fiscal year ending July 31, 2014.  Each director attended at least 75% of the total number of meetings of the Board and Board committees on which the director served. The Company has not adopted a policy requiring its directors to attend its annual meeting of stockholders and the Company did not hold an annual meeting last year.

Code of Conduct

We have adopted a Code of Conduct that applies to all directors and officers. The code describes the legal, ethical and regulatory standards that must be followed by the directors and officers of the Company and sets forth high standards of business conduct applicable to each director and officer. As adopted, the Code of Conduct sets forth written standards that are designed to deter wrongdoing and to promote, among other things:

(1) honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;

(2) full, fair accurate, timely and understandable disclosure in reports and documents that we file with, or submit to, the SEC and in other public communications made by us;

(3) compliance with applicable governmental laws, rules and regulations;

(4) the prompt internal reporting of violations of the code to the appropriate person or persons identified in the code; and

(5) accountability for adherence to the code.

We revised the Code of Conduct during the year ended July 31, 2013.  A copy of our Code of Conduct is incorporated by reference as Exhibit 14.1 to this Form 10-K.

Stockholder Communications with the Board

Our stockholders and other interested parties may communicate with members of the Board by submitting such communications in writing to our Secretary, Kathi Brogdon, who, upon receipt of any communication other than one that is clearly marked “Confidential,” will note the date the communication was received, open the communication, make a copy of it for our files and promptly forward the communication to the director(s) to whom it is addressed. Upon receipt of any communication that is clearly marked “Confidential,” our Secretary will not open the communication, but will note the date the communication was received and promptly forward the communication to the director(s) to whom it is addressed. If the correspondence is not addressed to any particular Board member or members, the communication will be forwarded to a Board member to bring to the attention of the Board.

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Compliance with Section 16(a) of the Exchange Act

Section 16(a) of the Exchange Act requires our directors and officers, and the persons who beneficially own more than 10% of our common stock, to file reports of ownership and changes in ownership with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Rule 16a-3 promulgated under the Exchange Act. Based solely on the reports received by us and on the representations of certain of the reporting persons, we believe that these persons have complied with all applicable filing requirements during the year ended July 31, 2014, except as follows:

Name	Number of forms filed late	Number of Transactions reported late
Kent P. Watts	2	3
Charles F. Dommer	1	1
Chistine P. Spencer	1	1
S. Chris Herndon	1	4
Kara Driver	1	2
Christopher Watts	1	2
Pasquale V. Scaturro	1	1
Tyler W. Moore	2	2
Jeremy Driver	1	1
Gregory M Larberg	1	1
Paul C. Schillmoller	2	3
KW Navigation Inc. (1)	1	2
CW Navigation Inc. (1)	1	2
KD Navigation Inc. (1)	1	2

(1) Companies owned 100% by Christopher Watts, nephew of our current Chairman

ITEM 11.  EXECUTIVE COMPENSATION

Summary Compensation of Named Executive Officers

The following table sets forth information concerning the compensation of our Chief Executive Officer, Chief Accounting Officer (as well as persons with respect to whom disclosure would have been required had they been serving in such roles as of the end of the applicable fiscal years) and the two most highly compensated officers other than the Chief Executive Officer and Chief Accounting Officer (collectively, our “Named Executive Officers”) during our fiscal years ended July 31, 2014 and 2013:

Summary Compensation

Name and Principal Position	Year	Salary		Bonus		Stock Awards (2)		Option Awards		Non-Equity Incentive Plan Compensation		Non-Qualified Deferred Compensation Earnings		All Other Compensation Earnings		Total (1)
Kent P. Watts (3)	2014	$	-	$	-	$	14,621	$	-	$	-	$	-	$	-	$	14,621
CEO and Chairman
Christine P. Spencer (4)	2014	$	132,923	$	-	$	144,000	$	-	$	-	$	-	$	-	$	276,923
Chief Accounting Officer
Craig Alexander	2014	$	185,000	$	-	$	185,000	$	-	$	-	$	-	$	-	$	370,000
Vice President, non-executive officer
Pasquale V. Scaturro	2014	$	75,257	$	-	$	23,518	$	-	$	-	$	-	$	-	$	98,775
Former CEO (5)
Tyler W. Moore	2014	$	20,584	$	-	$	152,369	$	-	$	-	$	-	$	-	$	172,953
Former CFO (6)
Charles F. Dommer	2014	$	99,205	$	-	$	13,320	$	-	$	-	$	-	$	-	$	112,525
President and COO (7)
Jeremy G. Driver (8)	2014	$	111,724	$	-	$	-	$	-	$	-	$	-	$	-	$	111,724
Former President and CEO	2013	$	175,000	$	-	$	-	$	-	$	-	$	-	$	-	$	175,000
Sara Berel-Harrop (9)	2014	$	162,163	$	-	$	-	$	-	$	-	$	-	$	-	$	162,163
Former Secretary, Treasurer & CFO	2013	$	134,809	$	-	$	-	$	-	$	-	$	-	$	-	$	134,809
Steven L. Carter (10)	2014	$	65,718	$	-	$	-	$	-	$	-	$	-	$	-	$	65,718
Former Vice President, Operations	2013	$	178,692	$	-	$	-	$	-	$	-	$	-	$	-	$	178,692

(1)  Does not include perquisites and other personal benefits, or property, unless the aggregate amount of such compensation is more than $10,000.  None of our executive officers received any Non-Equity Incentive Plan Compensation or Nonqualified Deferred Compensation Earnings during the periods presented.

(2) Represents the fair value of the grant of shares of our common stock calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718.

(3) Appointed as Chief Executive Officer on August 8, 2014.

(4) Appointed as Chief Accounting Officer on June 13, 2014.

(5) Effective November 15, 2013, Mr. Scaturro  was appointed as Chief Executive Officer of the Company. Mr. Scaturro resigned as Chief Executive Officer of the Company on August 8, 2014.

(6) Mr. Moore was appointed as Chief Financial Officer of the Company effective December 2, 2013 and resigned as Chief Financial Officer effective March 31, 2014.

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(7) Appointed as President and COO of the Company effective October 27, 2013.

(8) Effective on October 27, 2013, Mr. Driver resigned as President of the Company and effective on November 15, 2013, Mr. Driver resigned as Chief Executive Officer of the Company.

(9) Effective November 25, 2013, Ms. Berel-Harrop resigned as Secretary of the Company. Effective on December 2, 2013, Ms. Berel-Harrop resigned as Chief Financial Officer of the Company and was appointed as Chief Accounting Officer. On January 7, 2014, Ms. Berel-Harrop resigned as Chief Accounting Officer and Treasurer.

(10) Mr. Carter’s employment as Vice President Operations was terminated effective August 30, 2013.

Board of Directors Compensation:

Our directors who are also executive officers receive compensation for management services provided to the Company and thus they do not receive separate compensation for their services as directors.  In February 2013, we adopted a standard compensation package for independent directors as follows:

● $30,000 per year for serving on the board of directors (updated to $8,000 per quarter effective December, 2012,

● $2,000 per year for serving as a committee chair,

● Meeting fees of $2,000 per meeting for any board meetings other than four quarterly regular meetings, and

● Meeting fees of $1,500 per meeting for any committee meetings other than four quarterly regular meetings.

The following table provides information regarding compensation during the year ended July 31, 2014 earned by directors who are not executive officers.  Our directors who are executive officers do not receive additional compensation for their service as directors and their compensation is disclosed in the “Summary Compensation” Table above.

Name	Fees Earned or Paid in Cash		Option Awards (1)		All Other Compensation		Total
	($)		($)		($)		($)
Gregory M. Larberg (2) (3)	$	-	$	-	$	14,621	$	14,621
Paul C. Schillmoller (2) (3)	$	-	$	-	$	14,621	$	14,621
Pasquale V. Scaturro (3) (4)	$	-	$	-	$	23,518	$	23,518
S. Chris Herndon	$	22,000	$	-	$	15,955	$	37,955
John E. Brewster, Jr. (5)	$	14,000	$	-	$	-	$	14,000
Leonard Garcia (6)	$	14,000	$	-	$	-	$	14,000
Jeremy G. Driver (7)	$	-	$	-	$	-	$	-
Steven L. Carter (8)	$	-	$	-	$	-	$	-

* The table above does not include the amount of any expense reimbursements paid to the above directors.  No directors received any Stock Awards, Option Awards, Non-Equity Incentive Plan Compensation, or Nonqualified Deferred Compensation Earnings during the period presented.  Does not include perquisites and other personal benefits, or property, unless the aggregate amount of such compensation is more than $10,000.

(1) Represents the fair value of the grant of certain options to purchase shares of our common stock calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718.

(2) Appointed as members of the Board of Directors effective January 17, 2014.

(3) Resigned as members of the Board of Directors effective July 18, 2014.

(4) Appointed as a member of the Board of Directors effective October 11, 2013.

(5) Resigned effective November 1, 2013.

(6) Resigned effective October 31, 2013.

(7) Resigned as Chairman effective October 11, 2013 and as a member of the Board of Directors effective November 22, 2013.

(8) Resigned effective September 17, 2013.

Outstanding Equity Awards

As of July 31, 2014 no Executive Officer had any outstanding equity awards outstanding.  No Executive Officers had any stock options outstanding which were exercisable or unexercisable as of July 31, 2014.  Additionally, no Named Executive Officers had any unearned securities awards outstanding as of July 31, 2014.

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Employment, Consulting and Services Agreements

The following summary of certain material terms of the employment, consulting or services agreements we have entered into with certain of our officers or employees is not complete and is qualified in its entirety to the full text of each such agreement, which have been filed with the SEC as described in the list of exhibits to this annual report.

Charles F. Dommer Employment Agreement

Effective March 1, 2014, the Company entered into an employment agreement with Charles F. Dommer, pursuant to which Mr. Dommer agreed to serve as an employee of the Company for a term of one year.  Pursuant to the agreement, Mr. Dommer’s salary is $120,000 per year.  If Mr. Dommer’s employment is terminated by the Company in connection with a Change of Control (as defined in the agreement), either involuntarily by the Company or voluntarily by Mr. Dommer within 90 days of such Change of Control, the Company is required to continue paying him his salary for one year after such termination date.  Additionally, in the event the agreement is terminated by the Company for any reason other than cause or by Mr. Dommer for good reason (each as defined in the agreement), Mr. Dommer is due six months of salary as a severance payment.

Effective July 19, 2014, the Company entered into a replacement employment agreement with Charles F. Dommer, pursuant to which Mr. Dommer agreed to serve as the President of the Company for a term of one year.  Pursuant to the agreement, Mr. Dommer’s salary is $240,000 per year.  Mr. Dommer was also due a bonus of $20,000 in connection with the Company closing certain financing transactions which were consummated and which bonus was paid in August 2014.  Finally, Mr. Dommer is due a bonus equal to 2% of the net cash proceeds received by the Company for any working interest purchased from the Company by any joint venture with regard to any international concessions and operated by the Company. If Mr. Dommer’s employment is terminated by the Company in connection with a Change of Control (as defined in the agreement), either involuntarily by the Company or voluntarily by Mr. Dommer within 90 days of such Change of Control, the Company is required to continue paying his salary and reimburse him for insurance payments for one year after such termination date.  Additionally, in the event the agreement is terminated by the Company for any reason other than cause or by Mr. Dommer for good reason (each as defined in the agreement), Mr. Dommer is due six months of salary as a severance payment.

Christine P. Spencer Employment Agreement

Effective June 12, 2014, the Company entered into an employment agreement with Christine P. Spencer, pursuant to which Ms. Spencer agreed to serve as the Chief Accounting Officer for a term of one year, at a salary of $144,000 per year.  If Ms. Spencer’s employment is terminated by the Company in connection with a Change of Control (as defined in the agreement), either involuntarily by the Company or voluntarily by Ms. Spencer within 90 days of such Change of Control, the Company is required to continue paying her salary and reimburse her for insurance payments for one year after such termination date.  Additionally, in the event the agreement is terminated by the Company for any reason other than cause or by Ms. Spencer for good reason (each as defined in the agreement), Ms. Spencer is due twelve months of salary as a severance payment.

Carter Professional Services Agreement (Terminated)

On December 20, 2006, our Board of Directors authorized and approved the execution of the “Carter Professional Services Agreement”. The initial term of the agreement was two years expiring on November 30, 2008, and the agreement was amended to increase Mr. Carter’s compensation in June 2011. Pursuant to the terms and provisions of the Carter Professional Services Agreement: (i) Steven Carter shall provide duties to us commensurate with his then executive position as our Vice President of Operations; (ii) we would pay to Mr. Carter a monthly fee of $14,583.33; (iii) we approved the issuance of 20,000 shares of our common stock at a price of $0.025 per share (on a post-share consolidation basis); (iv) we approved the granting of an aggregate of not less than 24,000 options to purchase shares of our common stock at $8.75 per share (amended to be $2.50 per share) for a ten year term (on a post-share consolidation basis); and (v) the Carter Professional Services Agreement may be terminated without cause by either of us by providing prior written notice of the intention to terminate at least 90 days (in the case of our Company after the initial term) or 30 days (in the case of Mr. Carter) prior to the effective date of such termination.  In August, 2013, we terminated the agreement.  In accordance with the terms of the agreement, he received the fee due under the terms of the agreement through the end of November 2013.

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Jeremy G. Driver Agreement (2009)(Terminated)

Effective December 1, 2009, we entered into an executive services agreement with Mr. Driver, which was revised in June 2011 to increase his monthly fee, pursuant to which he is to perform such duties and responsibilities as set out in the agreement and as our Board of Directors may from time to time reasonably determine and assign as is customarily performed by a person in an executive position with our Company.  In consideration for his services under the agreement, as amended, we have agreed:

● to pay Mr. Driver a monthly fee of $14,583.33;

● to pay Mr. Driver a one-time signing bonus of $20,000;

● to provide Mr. Driver with industry standard bonuses, from time to time, based, in part, on the performance of the Company and the achievement by Mr. Driver of reasonable management objectives, as determined by the Company’s Board of Directors in good faith;

● to provide Mr. Driver with three weeks paid vacation;

● to provide Mr. Driver with a monthly benefits stipend of $450 together with full participation, at the Company’s expense, in the Company’s current medical services and life insurance benefits programs for management and employees; and

● to grant Mr. Driver incentive stock options to purchase not less than an aggregate of 100,000 common shares of the Company, at an exercise price $5.00 per share (amended to be $2.50 per share), vesting as to one-quarter of said stock options on the date of grant (that being as to 25,000) and on each day which is six months thereafter in succession for each remaining one-quarter of the optioned common shares, and all being exercisable for a period of three years from the date of grant and in accordance with the provisions of the Company’s current Stock Incentive Plan.

The initial term of the agreement was one year ending on December 1, 2010, and the agreement was subject to automatic renewal on a monthly basis unless either the Company or Mr. Driver provides written notice of an intention not to renew the agreement not later than 30 days prior to the end of the then-current initial term or renewal of the agreement.  In October 2013, this agreement was terminated and we entered into a new employment agreement with Mr. Driver, as described below.

Jeremy G. Driver Agreement (2013)(Terminated)

On October 11, 2013, we entered into a new agreement with Mr. Driver, which was modified on October 27, 2013 and is effective October 1, 2013.  In consideration for his services under the agreement, as amended, we agreed to provide Mr. Driver with a monthly salary of $14,583.33, participation in company benefits programs, and four weeks paid vacation.  The agreement provides for Mr. Driver to be paid six months’ salary as severance in the event of:

● termination by the Company for other than cause,

● termination by Mr. Driver for “Good Reason”, which includes a diminishment of job functions or responsibilities and attempts by the Company to relocate Mr. Driver, or

● termination by Mr. Driver for any reason within 90 days of a change in control of the Company.

The initial term of the agreement is one year ending on October 1, 2014, and the agreement is subject to automatic renewal for consecutive one year periods unless either the Company or Mr. Driver provides written notice of an intention not to renew the agreement not later than 60 days prior to the end of the then-current initial term or renewal of the agreement.

Effective October 11, 2013, Mr. Driver resigned as Chairman and as a member of the Board of Directors of the Company.

Sarah Berel-Harrop Agreement (Terminated)

On October 11, 2013, we entered into an employment agreement with Ms. Berel-Harrop, which was effective October 1, 2013.  In consideration for her services under the agreement, as amended, we agreed and provide Ms. Berel-Harrop with a monthly salary of $12,500, participation in company benefits programs, and three weeks paid vacation.  The agreement provides for Ms. Berel-Harrop to be paid six months’ salary as severance in the event of:

● termination by the Company for other than cause,

● termination by Ms. Berel-Harrop for “Good Reason”, which includes a diminishment of job functions or responsibilities and attempts by the Company to relocate Ms. Berel-Harrop, or

● termination by Ms. Berel-Harrop for any reason within 90 days of a change in control of the Company.

The initial term of the agreement is one year ending on October 1, 2014, and the agreement is subject to automatic renewal for consecutive one year periods unless either the Company or Ms. Berel-Harrop provides written notice of an intention not to renew the agreement not later than 60 days prior to the end of the then-current initial term or renewal of the agreement.

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Effective November 25, 2013, Ms. Berel-Harrop resigned as Secretary of the Company. Effective on December 2, 2013, Ms. Berel-Harrop resigned as Chief Financial Officer of the Company and was appointed as Chief Accounting Officer. On January 7, 2014, Ms. Berel-Harrop resigned as Chief Accounting Officer and Treasurer.

Craig Alexander Agreement

On October 11, 2013, we entered into an employment agreement with Mr. Alexander, which is effective October 1, 2013. In consideration for his services under the agreement, as amended, we have agreed to provide Mr. Alexander with a monthly salary of $15,417.67, participation in Company benefits programs, and three weeks paid vacation.  The agreement provides for Mr. Alexander to be paid six months’ salary as severance in the event of:

● termination by the Company for other than cause,

● termination by Mr. Alexander for “Good Reason”, which includes a diminishment of job functions or responsibilities and attempts by the Company to relocate Mr. Alexander, or

● termination by Mr. Alexander for any reason within 90 days of a change in control of the Company.

The initial term of the agreement was one year ending on October 1, 2014, and the agreement is subject to automatic renewal for consecutive one year periods unless either the Company or Mr. Alexander provides written notice of an intention not to renew the agreement not later than 60 days prior to the end of the then-current initial term or renewal of the agreement. The agreement automatically renewed.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth certain information concerning the number of shares of our voting stock owned beneficially as of October 22, 2014 by: (i) each person (including any group) known to us to own more than 5% of our shares of common stock; (ii) each of our directors; (iii) each of our officers; and (iv) our officers and directors as a group.

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting and/or investing power with respect to securities. These rules generally provide that shares of common stock subject to options, warrants or other convertible securities that are currently exercisable or convertible, or exercisable or convertible within 60 days of the applicable date, are deemed to be outstanding and to be beneficially owned by the person or group holding such options, warrants or other convertible securities for the purpose of computing the percentage ownership of such person or group, but are not treated as outstanding for the purpose of computing the percentage ownership of any other person or group. 

 To our knowledge, except as indicated in the footnotes to this table and pursuant to applicable community property laws, (a) the persons named in the table have sole voting and investment power with respect to all shares of common stock shown as beneficially owned by them, subject to applicable community property laws; and (b) no person owns more than 5% of our common stock.  Unless otherwise indicated, the address for each of the officers or directors listed in the table below is 800 Gessner, Suite 375, Houston, Texas 77024.

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Title of Class	Name and Address of Beneficial Owner (1)	Amount and Nature of Beneficial Owner		Percent of Class
Directors and Officers:
Common Stock	Kent Watts	3,207,453	(2)	14.76%
	800 Gessner, Suite 375
	Houston, Texas, U.S.A. 77024
Common Stock	Christine P. Spencer	32,814		*
	800 Gessner, Suite 375
	Houston, Texas, U.S.A. 77024
Common Stock	Charles F. Dommer	841,702		3.97%
	800 Gessner, Suite 375
	Houston, Texas, U.S.A. 77024
Common Stock	S. Chris Herndon	68,945	(3)	*
	800 Gessner, Suite 375
	Houston, Texas, U.S.A. 77024
	Directors and officers together (4 persons)	4,150,914		19.04%
	Major Stockholders:
Common Stock	Christopher Watts	7,397,673	(4)	34.92%
	14019 SW Frwy #301-600
	Sugar Land, Texas, U.S.A. 77478
Common Stock	Pasquale Scaturro	2,707,058		12.78%
	1700 Garland St.
	Lakewood, CO 80215
Common Stock	Michael Watts	1,669,089	(5)	7.64%
	14019 SW Frwy #301-600
	Sugar Land, Texas, U.S.A. 77478

* Indicates beneficial ownership of less than 1% of the total outstanding common stock.

(1) Under Rule 13d-3 of the Exchange Act a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares, and/or (ii) investment power, which includes the power to dispose or direct the disposition of shares. In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares within 60 days of the date as of which the information is provided.

(2) Includes shares owned directly plus 8,188 preferred shares convertible into 545,833 common shares.

(3) Includes 66,667 option shares.

(4) Christopher Watts is the 100% owner of CW Navigation, KD Navigation, and KW Navigation. Each of the three entities owns 2,465,891 shares, totalling 7,397,673.

(5) Includes common shares owned by Geoserve Marketing, an entity owned 100% by Michael Watts, 666,667 of warrants owned by Geoserve Marketing, as well as shares owned personally by Michael Watts.

Changes in Control

We are unaware of any contract, or other arrangement or provision, the operation of which may at a subsequent date result in a change of control of our company.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Except as described below, none of the following parties has had any material interest, direct or indirect, in any transaction with us during our last two fiscal years or in any presently proposed transaction that has or will materially affect us:

(1) any of our directors or officers;

(2) any person who beneficially owns, directly or indirectly, shares carrying more than 5% of the voting rights attached to our outstanding shares of common stock; or

(3) any member of the immediate family (including spouse, parents, children, siblings and in-laws) of any of the above persons.

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Galveston Bay

Immediately following our acquisition of Galveston Bay Energy, LLC, on February 15, 2011, we sold 15% of our own aggregate working interest in the Galveston Bay fields for $1,400,000 in cash to SPE Navigation 1, LLC (“SPE”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a former Director and our former Chief Executive Officer. SPE had the right to acquire an additional 10% of our own aggregate working interest in the Galveston Bay fields within 90 days for $1,150,000.

Effective on September 26, 2011, we closed on our acquisition of SPE from CW Navigation Inc., KD Navigation Inc. and KW Navigation Inc., each a Texas corporation (collectively, the “Sellers”). The material assets of SPE consist of certain oil and gas working interests in and to four producing oil and gas fields located in Galveston Bay, Texas, together with one million shares of Hyperdynamics Corporation (NYSE: HDY).  Pursuant to the terms of the Company’s Purchase and Sale Agreement with the Sellers and SPE regarding this matter, the Company acquired the Sellers’ 100% interest in SPE for total consideration consisting of 3,800,000 restricted common shares of the Company issued at a deemed issuance price of $2.50 per share (on a post-share consolidation basis).  CW Navigation Inc. KD Navigation Inc. and KW Navigation Inc. are owned 100% by Christopher Watts, who is related to our CEO, Mr. Kent Watts.

Namibia Exploration, Inc.

We entered into a Share Exchange Agreement, dated August 7, 2012 (the “Share Exchange Agreement”) with each of Namibia Exploration, Inc. (“NEI”), a company organized under the laws of the state of Nevada, and the shareholders of NEI (each a “Vendor” and collectively, the “Vendors”), whereby we acquired the right to acquire all of the issued and outstanding common shares in the capital of NEI from the Vendors in exchange for the issuance of up to 24,900,000 restricted common shares of Duma to the Vendors (the “Acquisition Shares”) on a pro-rata basis in accordance with each Vendor’s percentage ownership in NEI (the “Acquisition”). NEI holds the rights to a 39% working interest in an onshore petroleum concession (the “Concession”), located in the Republic of Namibia, measuring approximately 5.3 million acres and covered by Petroleum Exploration License No. 0038 as issued by the Republic of Namibia Ministry of Mines and Energy.

We completed the Acquisition on September 6, 2012, and as a result, NEI became a wholly-owned subsidiary of Duma.  As a result, Duma, through NEI, has acquired and been assigned a 39% working interest (43.33% cost responsibility) in and to the Concession.  Duma now holds its indirect working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. (“NPC Namibia”) and Hydrocarb Namibia Energy Corporation (“Hydrocarb Namibia”), a company chartered in the Republic of Namibia and which is a majority owned subsidiary of Hydrocarb Corporation (“Hydrocarb”), a company organized under the laws of the State of Nevada.  Hydrocarb Namibia, as operator of the Concession, now holds a 51% working interest (56.67% cost responsibility) in the Concession and NPC Namibia now holds a 10% carried working interest in the Concession.  The assignment of the 39% working interest to NEI from Hydrocarb Namibia received the approval of the government of the Republic of Namibia on August 23, 2012.

Pursuant to the terms of the Share Exchange Agreement, Duma is required to issue the Acquisition Shares, as consideration for the Acquisition, in accordance with the following milestones which must be reached within 10 years after the closing of the Acquisition (the “Closing”):

(a) 830,000 of the Acquisition Shares have been issued;

(b) a further 830,000 of the Acquisition Shares will be issued when and if Duma’s 10-day volume-weighted average market capitalization reaches $82,000,000;

(c) a further 2,490,000 of the Acquisition Shares will be issued when and if Duma’s 10-day volume-weighted average market capitalization reaches $196,000,000; and

(d) a further and final 4,150,000 of the Acquisition Shares will be issued and if Duma’s 10-day volume-weighted average market capitalization reaches $434,000,000.

Duma will maintain 100% ownership of NEI after Closing even if one or more of the market capitalization milestones have not been attained within 10 years from the Closing.

In conjunction with the HCN acquisition in December 2013, the HEC Board of Directors authorized the immediate issuance of these contingently issuable 7,470,000 shares of our common stock to the former owners of NEI.  We issued those shares on December 9, 2013.

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The Vendors under the Share Exchange Agreement were Michael Watts (the father-in-law of Jeremy Driver, our former Chief Executive Officer and director), CW Navigation Inc. , KW Navigation Inc. , and KD Navigation Inc. The Navigation companies are beneficially owned by Christopher Watts, the nephew of our current Chairman.

Carter E & P, LLC

A company controlled by one of our former officers (Steven Carter) operated our Barge Canal properties, the Curlee Prospect in Bee County, Texas and the Dix Prospect in San Patricio County, Texas.  Revenues generated from these properties were $39,274 and $643,203 for the years ended July 31, 2014 and 2013, respectively.  In addition, lease operating costs incurred from these properties were $23,259 and $224,047 for the years ended July 31, 2014 and 2013, respectively.

As of July 31, 2014 and 2013, respectively, we had outstanding accounts receivable associated with these properties of $0 and $91,967 and no accounts payable.

Working Interest

During January 2012, we sold half of our working interest in a well, the State Tract 9-12A#4, to third parties.  The father of our former Chief Financial Officer, George Bert Harrop, and a company controlled by the father-in-law of our former Chief Executive Officer, Lifestream, LLC, each purchased a 5% interest in the well.  The costs associated with the drilling and completion operations on the well through July 31, 2012 were approximately $6.6 million for all participants.  Mr. Harrop’s and Lifestream’s share of the operations were $8,568 and $330,151 each during the years ended July 31, 2014, July 31, 2013 and July 31, 2012, respectively.

HCN Acquisition

On December 9, 2013 (“Acquisition Date”), we acquired HCN (“HCN Acquisition”) pursuant to a Share Exchange Agreement (“HCN Agreement”) dated November 27, 2013.  The purchase price was 8,396,667 shares of HEC’s common stock to HCN’s shareholders in exchange for 100% of the outstanding equity interest in HCN and 8,188 shares of HEC Series A Preferred Stock to a holder of convertible preferred stock in HCN in exchange of 100% of the holder’s preferred stock in HCN. At date of closing the 8,396,667 shares of common stock issued had a market valuation of $64,990,200 (based on market close of $7.74 on December 9, 2013) and the preferred stock issued had a value of $3,275,200 (8,188 shares at par value of $400).

In addition, the HCN 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.

Independent Directors

S. Chris Herndon is an independent director of our Company as provided in the listing standards of the NYSE MKT Equities Exchange.

Additional Agreements, Transactions and Understandings

During 2011, we entered into a consulting contract with a company controlled by Michael Watts, the father-in-law of Jeremy Driver, our former Chief Executive Officer and Director, as detailed in Note 9 – Capital Stock.  We recognized expense of $196,384 from this contract during the years ended July 31, 2013.  Due to the expiration of the contract for services $6,754 was recognized in the year ended July 31, 2014.

In December 2012, we acquired a 366.85 acre tract of property (the “Dix Prospect”), in San Patricio County, Texas. As of July 31, 2013 we incurred $76,938 in acquisition and land costs. In February 2013, we sold a 75% working interest in the prospect to partners on a third for a quarter basis, under which the 75% interest holders will carry 25% of the working interest to the casing point of the initial well drilled on the prospect. In January 2013, we sold 2% of our 25% carried working interest to Carter E&P, a company owned by our former Vice President of Operations and retained a 23% working interest which is carried to the casing point of the initial well.

Effective September 1, 2013, we conveyed our interest in the Dix, Melody, Curlee, Palacios and Illinois properties to Carter E&P, LLC (“Carter E&P”) in conjunction with our termination of Steven Carter as Vice President of Operations for $0 cash proceeds and the assumption of the abandonment liabilities of $4,381. In accordance with full cost rules, we recognized no gain or loss on the sale. During the year ended July 31, 2013, Carter E&P operated several properties onshore in South Texas, including our Barge Canal properties. Although he was not a related party after September 2013, we considered the transactions with his company during his tenure as an officer of the Company as related party transactions because they were not compensation or ordinary course of business, and because he was a related party at the time they occurred.

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Effective on August 8, 2014, Pasquale V. Scaturro resigned as the Chief Executive Officer of the Company provided that on the same date Mr. Scaturro entered into a consulting agreement with the Company and agreed to provide the Company Geological and Geophysical consulting pertaining to the Company’s oil and gas concession in Namibia.  Pursuant to the agreement we are required to pay Mr. Scaturro $10,000 per month (for 12 months) and provide him a success fee of $250,000 upon the sale or joint venture of the Company’s Owambo Concession in Namibia. The agreement has a 180 day term, renewable thereafter in 30 day periods for an additional 180 days.

Kirby Caldwell Note

On September 6, 2013, HCN sold 191,667 shares of HEC common stock to an employee of HCN 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 market or NYSE stock exchange. 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 market or stock exchange, we will receive up to $1,000,000, or the note can be paid earlier at the discretion of the other party. We collected $675,000 in cash on this note receivable through July 31, 2014.  At July 31, 2013, these shares were classified as treasury stock within equity at the cost HCN obtained them from outside entities for services performed following the consolidation of comparative periods for acquired entities under common control (See Note 2 –Acquisitions).  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.

Kent Watts Note

In November 2013, we issued a promissory note for funds received from Mr. Kent Watts, Our Chariman, 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.  Additonally, 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 July 31, 2014.  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.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Our current independent auditor, MaloneBailey, LLP, served as our independent registered public accounting firm and audited our financial statements for the fiscal year ended July 31, 2014 and 2013. Aggregate fees for professional services rendered to us by our auditor are set forth below:

Year Ended July 31,	2014		2013
Audit Fees	$	167,500	$	103,000
Audit -Related Fees		-		1,500
Other		-		-
Tax Fees		-		19,319
Total	$	167,500	$	123,819

Audit Fees

Audit fees are the aggregate fees billed for professional services rendered by our independent auditors for the audit of our annual financial statements, the review of the financial statements included in each of our quarterly reports and services provided in connection with statutory and regulatory filings or engagements.

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Audit Related Fees

Audit related fees are the aggregate fees billed by our independent auditors for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not described in the preceding category. Specifically, during the year ended July 31, 2013, the independent auditor billed $1,500 for services provided in conjunction with responding to an SEC comment letter.

Tax Fees

Tax fees are billed by our independent auditors for tax compliance, tax advice and tax planning.

All Other Fees

All other fees include fees billed by our independent auditors for products or services other than as described in the immediately preceding three categories.

Policy on Pre-Approval of Services Performed by Independent Auditors

It is the policy of our Board of Directors that all services to be provided by our independent registered public accounting firm, including audit services and permitted audit-related and non-audit services, must be pre-approved by our Board of Directors. Our Board of Directors pre-approved all services, audit and non-audit related, provided to us by our independent registered public accounting firm for 2014 and 2013.

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PART IV

ITEM 15.  EXHIBITS

(e) Documents filed as part of this report.

(1) All financial statements

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated  Balance Sheets as of July 31, 2014 and 2013	F-3
Consolidated Statements of Operations and Comprehensive Loss for the years ended July 31, 2014 and 2013	F-4
Consolidated Statements of Changes in Stockholders’ Equity for the years ended July 31, 2014 and 2013	F-5
Consolidated  Statements of Cash Flows for the years ended July 31, 2014 and 2013	F-6
Notes to Consolidated Financial Statements	F-7

(2) Financial Statement Schedules

All financial statement schedules have been omitted, since the required information is not applicable or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and notes thereto included in this Form 10-K.

(3) Exhibits required by Item 601 of Regulation S-K

The following exhibits are filed with this Annual Report on Form 10-K/A:

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SIGNATURES

Pursuant to the requirements of Section 13 and 15 (d) 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.

By:	/s/ Kent P Watts
	Chief Executive Officer, Executive Chairman, and Director
	(Principal Executive Officer)
	Date: June 9, 2015
By:	/s/Christine P. Spencer
	Chief Accounting Officer
	(Principal Financial Officer and Principal Accounting Officer)
	Date: June 9, 2015

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EXHIBIT INDEX

Exhibit Number	Description of Exhibit
3.1 (1)	Articles of Incorporation and amendments thereto, dated July 19, 2005, October 18, 2005 and September 5, 2006
3.2 (10)	Certificate of Change filed with the Nevada Secretary of State on March 22, 2012
3.3 (10)	Articles of Merger filed with the Nevada Secretary of State on March 22, 2012
3.4 (11)	Certificate of Amendment filed with the Nevada Secretary of State on May 16, 2012
3.5 (18)	Certificate of Designation of Series A 7% Convertible Voting Preferred Stock
3.6 (19)	Amendment to Articles of Incorporation (name change and increase in authorized shares of stock to 1,000,000,000) February 4, 2014
3.7 (22)	Certificate of Change Pursuant to NRS 78.209 (April 14, 2014), affecting a reduction in authorized shares of common stock to 333,333,334 shares of common stock and affecting a 1:3 reverse stock split
3.8 (14)	Amended and Restated By-Laws (July 20, 2014)
4.1 (2)	Form of Warrant Certificate issued to Subscribers pursuant to the October 15, 2009 Private Placement
4.2  (3)	Form of Warrant Certificate issued to Subscribers pursuant to the November 13, 2009 Private Placement
10.1 (1)	Sale Contract for Oil and Gas Leases between Energy Program Accompany, LLC and Penasco Petroleum, Inc., dated August 24, 2006 (regarding the Holt, McKay and Strahan Leases)
10.2 (1)	Letter Agreement between Penasco Petroleum, Inc. and Tradestar Resources Corporation, dated September 1, 2006
10.3 (1)	Assignment, Bill of Sale and Conveyance between OPEX Energy LLC and Penasco Petroleum, Inc., dated effective August 1, 2006 (regarding the Welder Lease)
10.4 (1)	Participation Agreement between Rockwell Energy, LLC and the Company, dated October 2005 (regarding the Janssen Lease)
10.5 (1)	Oil, Gas and Mineral Lease between Henry J. Janssen Jr. and Penasco Petroleum, Inc., dated July 2006 (regarding the Janssen Lease)
10.6 (1)	Assignment and Bill of Sale between Penasco Petroleum, Inc. and ETG Energy Resources, dated October 2006, and Assignment between ETG Energy Resources and Penasco Petroleum, Inc., dated December 2006 (regarding the Janssen Lease)
10.7 (1)	Ratification Letter between Marmik Oil Company and Penasco Petroleum, Inc., dated October 2007 (regarding Little Mule Creek Project)
10.8 (1)	Assignment between Marmik Oil Company and Penasco Petroleum, Inc., dated November 2007 (regarding Little Mule Creek Project)
10.9 (4)	2009 Restated Stock Incentive Plan
10.10 (1)***	Professional Services Retainer Contract between the Company and Steven Carter, dated December 2006
10.11 (2)	Form of Securities Purchase Agreement regarding October 15, 2009 Private Placement
10.12 (2)	Form of Registration Rights Agreement regarding October 15, 2009 Private Placement
10.13 (3)	Form of Securities Purchase Agreement regarding November 13, 2009 Private Placement
10.14 (3)	Form of Registration Rights Agreement regarding November 13, 2009 Private Placement
10.15 (5)***	Executive Services Consulting Agreement between the Company and Jeremy Glenn Driver dated for reference effective on December 1, 2009
10.16 (6)	Assignment of Oil and Gas Lease between Penasco Petroleum, Inc. and Chinn Exploration Company, dated September 13, 2010
10.17 (7)	Purchase and Sale Agreement by and among ERG Resources, LLC, Galveston Bay Energy, LLC and Strategic American Oil Corporation, dated January 18, 2011, as amended February 14, 2011
10.18 (7)	Geoserve Marketing, LLC Agreement, dated February 15, 2011
10.19 (7)	SPE Navigation 1, LLC Agreement to acquire work interest., dated February 15, 2011
10.20 (8)	Purchase and Sale Agreement among CW Navigation Inc., KD Navigation Inc., and KW Navigation Inc. (as the Seller parties), SPE Navigation I, LLC and Strategic American Oil Corporation, executed September 22, 2011
10.21 (9)	2010 Stock Incentive Plan
10.22 (9)	2011 Stock Incentive Plan
10.23 (9)	Farm-Out Agreement with Core Minerals, January 2011, as amended March 9, 2011
10.24 (12)	Share Exchange Agreement dated August 7, 2012
10.25 (12)	Consulting Services Agreement between Duma Energy Corp. and Hydrocarb Corporation, dated August 7, 2012
10.26 (13)	Joint Operating Agreement between Hydrocarb Namibia Energy Corporation and Namibia Exploration, Inc. as fully executed on September 6, 2012
10.27 (13)	Assignment Agreement between the Republic of Namibia Minister of Mines and Energy, Hydrocarb Namibia Energy Corporation (Proprietary) Limited and Namibia Exploration, Inc. as fully executed on August 23, 2012.

97

10.28 (16)	2013 Stock Incentive Plan
10.29 (15)***	Employment Agreement between the Company and Jeremy Glenn Driver effective October 1, 2013
10.30 (15)***	Employment Agreement between the Company and Sarah Berel-Harrop effective October 1, 2013
10.31 (15)	Form of Indemnification Agreement
10.32 (16)***	Employment Agreement between the Company and William Craig Alexander effective October 1, 2013
10.33 (21)	Secured Promissory Note (Kent P. Watts) - $600,000, dated April 18, 2014
10.34 (17)	Stock Exchange Agreement dated November 27, 2013, by and among Duma Energy Corp., a Nevada corporation (“DUMA”), Hydrocarb Corporation, a Nevada corporation (“HCN”), the holders of 100% of the shares of common stock and preferred stock of HCN and the holders of rights to acquire DUMA common stock and Exhibits Thereto
10.35 (23)	December 4, 2013 Sales Agreement and Note with SMDRE, LLC
10.36 (23)	August 8, 2014 (effective August 4, 2014) Amendment to Note Payable Terms with SMDRE, LLC
10.37 (24)	Credit Agreement dated as of August 15, 2014, by and among Hydrocarb Energy Corporation, as borrower, Shadow Tree Capital Management, LLC, as agent, and the Lenders thereto
10.38 (24)	Stock Grant Agreement between Hydrocarb Energy Corporation and the Lenders dated August 15, 2014
10.39 (24)	Guarantee and Collateral Agreement by Hydrocarb Energy Corporation and its subsidiaries in favor of the Lenders dated August 15, 2014
10.40 (24)	$1,136,363 Term Loan Note dated August 15, 2014 payable to Quintium Private Opportunity Fund, LP
10.41 (24)	$3,409,091 Term Loan Note dated August 15, 2014 payable to Shadow Tree Funding Vehicle A-Hydrocarb LLC
10.42 (25)	August 2014 Consulting Agreement with Pasquale V. Scaturro
10.43 (25)	March and July 2014 Employment Agreement with Charles F. Dommer
10.44 (25)	June 2014 Employment Agreement with Christine P. Spencer
10.45 (25)	Note Payable to Kent Watts
10.46 (25)	Note Receivable from Kirby Caldwell
14.1 (16)	Code of Conduct
21.1 (25)	Subsidiaries of Hydrocarb Energy Corp.
23.1*	Consent of MaloneBailey, LLP
23.2*	Consent of Ralph E. Davis Associates, Inc.
31.1*	Certification of Chief Executive Officer pursuant to Securities Exchange Act of 1934 Rule 13a-14(a) or 15d-14(a)
31.2*	Certification of Chief Accounting Officer pursuant to Securities Exchange Act of 1934 Rule 13a-14(a) or 15d-14(a)
32.1**	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350
99.1*	Report of Ralph E Davis Associates, Inc., dated August 21, 2014
99.2 (20)	Audited Financial Statements of Hydrocarb Corporation and its subsidiaries as of October 31, 2013 and December 31, 2012
99.3 (20)	Unaudited Pro Forma Information Relating to the Acquisition of Hydrocarb Corporation
101.INS+	XBRL INSTANCE DOCUMENT
101.SCH+	XBRL TAXONOMY EXTENSION SCHEMA
101.CAL+	XBRL TAXONOMY EXTENSION CALCULATION LINKBASE
101.DEF+	XBRL TAXONOMY EXTENSION DEFINITION LINKBASE
101.LAB+	XBRL TAXONOMY EXTENSION LABEL LINKBASE
101.PRE+	XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE

* Filed herewith.

** Furnished herewith.

*** Indicates management contract or compensatory plan or arrangement.

98

(1)Filed as an exhibit to our registration statement on Form S-1/A (Amendment No.1) filed with the Securities and Exchange Commission on February 8, 2008 and incorporated herein by reference (File Number 333-149070).

(2) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 16, 2009 and incorporated herein by reference (File Number 000-53313).

(3)Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on November 16, 2009 and incorporated herein by reference (File Number 000-53313).

(4)Filed as an exhibit to our Annual Report on Form 10-K filed with the Securities and Exchange Commission on November 12, 2009 and incorporated herein by reference (File Number 000-53313).
 

(5)Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2009 and incorporated herein by reference (File Number 000-53313).

(6)Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 20, 2010 and incorporated herein by reference (File Number 000-53313).

(7)Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on February 22, 2011 and incorporated herein by reference (File Number 000-53313).

(8)Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 22, 2011 and incorporated herein by reference (File Number 000-53313).

(9)Filed as an exhibit to our Annual Report on Form 10-K filed with the Securities and Exchange Commission on November 15, 2011 and incorporated herein by reference (File Number 000-53313).

(10)Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on April 4, 2012 and incorporated herein by reference (File Number 000-53313).

(11)Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on May 17, 2012 and incorporated herein by reference (File Number 000-53313).

(12)Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on August 8, 2012 and incorporated herein by reference (File Number 000-53313).

(13)Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 12, 2012 and incorporated herein by reference (File Number 000-53313).

(14)Filed as exhibit 3.1 to our Current Report on Form 8-K filed with the Securities and Exchange Commission on July 24, 2014 and incorporated herein by reference (File Number 000-53313).

(15)Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 16, 2013 and incorporated herein by reference (File Number 000-53313).
 

(16)Filed as an exhibit to our Annual Report on Form 10-K filed with the Securities and Exchange Commission on November 12, 2013 and incorporated herein by reference (File Number 000-53313).

(17)Filed exhibits to our Current Report on Form 8-K/A Amendment No. 1 filed with the Securities and Exchange Commission on June 3, 2014 and incorporated herein by reference (File Number 000-53313).

(18)Filed exhibit 3.1 to our Current Report on Form 8-K filed with the Securities and Exchange Commission on December 6, 2013 and incorporated herein by reference (File Number 000-53313).

(19)Filed exhibit 3.1 to our Current Report on Form 8-K filed with the Securities and Exchange Commission on February 10, 2014 and incorporated herein by reference (File Number 000-53313).

99

(20)Filed as part of our Current Report on Form 8-K/A Amendment No. 1 filed with the Securities and Exchange Commission on February 24, 2014 and incorporated herein by reference (File Number 000-53313).

(21)Filed as exhibit 10.1 of our Current Report on Form 8-K filed with the Securities and Exchange Commission on May 2, 2014 and incorporated herein by reference (File Number 000-53313).

(22)Filed exhibit 3.1 to our Current Report on Form 8-K filed with the Securities and Exchange Commission on May 7, 2014 and incorporated herein by reference (File Number 000-53313).

(23)Filed as exhibits to our Current Report on Form 8-K filed with the Securities and Exchange Commission on August 14, 2014 and incorporated herein by reference (File Number 000-53313).

(24)Filed as exhibits to our Current Report on Form 8-K filed with the Securities and Exchange Commission on August 21, 2014 and incorporated herein by reference (File Number 000-53313).

(25)           Filed as exhibits to our Annual Report on Form 10-K filed with the Securities and Exchange Commission on November 13, 2014 and incorporated herein by reference (File Number 000-53313).

+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.

100

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-197070 on Form S-8 of Hydrocarb Energy Corp. (the “Company”), of our report dated November 13, 2014, relating to the consolidated financial statements of the Company and subsidiaries appearing in the Annual Report on Form 10-K/A of the Company for the years ended July 31,  2014, and 2013.

/s/ MaloneBailey, LLP

www.malone-bailey.com

Houston, Texas

June 9, 2015

EX-23.2

EXHIBIT 23.2

CONSENT OF RALPH E DAVIS ASSOCIATES, INC.

As independent oil and gas consultants, Ralph E Davis Associates, Inc., hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K/A of Hydrocarb Energy Corp. (the “Company”) for the year ended July 31, 2014 (the “Annual Report”).

We also hereby further consent to the inclusion and use in the Annual Report of our report dated August 21, 2014, entitled “Hydrocarb Energy Corporation Estimated Future Reserves and Income As of July 31, 2014” (the “Report”) and to the inclusion of our Report as Exhibit 99.1 to the Annual Report.

We also consent to the incorporation by reference in Registration Statement No. 333-197070 on Form S-8 of the Company, of all references to our firm and all information from the Reports.

/s/ RALPH E DAVIS ASSOCIATES, INC.

RALPH E DAVIS ASSOCIATES, INC.

June 9, 2015

EX-31.1

EXHIBIT 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kent P. Watts, certify that:

1. I have reviewed this annual report on Form 10-K/A of Hydrocarb Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the consolidated financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in the report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have significant role in the registrant's internal control over financial reporting.

Date:	June 9, 2015
By:	/s/ Kent P. Watts
	Kent P. Watts
	Chief Executive Officer and a director
	(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Christine P. Spencer, certify that:

1. I have reviewed this annual report on Form 10-K/A of Hydrocarb Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the consolidated financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in the report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have significant role in the registrant's internal control over financial reporting.

Date:	June 9, 2015
By:	/s/ Christine P. Spencer
	Christine P. Spencer
	Chief Accounting Officer
	(Principal Accounting Officer)

EX-32.1

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 annual Report of Hydrocarb Energy Corp, on Form 10-K/A for the year ended July 31, 2014, 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:	June 9, 2015
By:	/s/ Kent P. Watts
	Kent P. Watts
	Chief Executive Officer and a director
	(Principal Executive Officer)

By:	/s/ Christine P. Spencer
	Christine P. Spencer
	Chief Accounting Officer
	(Principal Accounting Officer)

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.

EX-99.1

Exhibit 99.1

HYDROCARB ENERGY CORPORATION

Estimated Future Reserves

And Income

As of July 31, 2014

Table of Contents

Hydrocarb Energy Corporation

Table of Contents

Discussion
Letter
Reserves Definitions
Certificate of Qualifications
Economic Summary Report	Page
Total Company	1
Proved Producing	2
Proved Shut-In	3
Proved Behind Pipe	4
Proved Undeveloped	5
Field Expenses	6
One-line Summary – Sorted by Reserve Category, Field, and Lease	7-10
Proved Producing Economic Detail Report
Fishers Reef Field	11-15
Point Bolivar Field	16-17
Red Fish Reef Field	18-24
Trinity Bay Field	25-29
Proved Shut-In Economic Detail Report
Fishers Reef Field	30-31
Point Bolivar North Field	32-33
Red Fish Reef Field	34-39
Trinity Bay Field	40-43
Proved Behind Pipe Economic Detail Report
Fishers Reef Field	44-46
Red Fish Reef Field	47-53
Trinity Bay Field	54-56
Proved Undeveloped Economic Detail Report
Red Fish Reef Field	57-64
Trinity Bay Field	65-66
Field Expenses Economic Detail Report
Fishers Reef Field	67-69
Point Bolivar North Field	70-72
Red Fish Reef Field	73-75
Trinity Bay Field	76-78

Discussion

August 21, 2014

Hydrocarb Energy Corporation800 Gessner Rd., Suite 375Houston, TX 77024

Attention:	Pasquale Scaturro
	Chief Executive Officer

Re: Oil, Condensate, and Natural Gas ReservesSEC Non-Escalated AnalysisHydrocarb Energy CorporationAs of July 31, 2014

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 July 31, 2014, having completed the evaluation of said estimate of reserves based upon the information presented within this report, on August 21, 2014.

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.

1717 St. James Place, Suite 460    Houston, Texas 77056    Office 713-622-8955    Fax 713-626-3664    www.ralphedavis.com

Worldwide Energy Consultants Since 1924

Hydrocarb Energy Corporation	August 21, 2014
SEC Non-Escalated Analysis	Page 2 of 6
Oil, Condensate, and Natural Gas Reserves

We have also estimated the future net revenue and discounted present value associated with these reserves as of July 31, 2014, 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.

The results of our study related to our estimate of the Total Proved Reserves attributable to Hydrocarb and remaining to be produced as of July 31, 2014 are as follows:

Estimated Proved ReservesNet to Hydrocarb Energy CorporationSEC Non-Escalated AnalysisAs of July 31, 2014

	Proved
	Producing		Shut In		Behind Pipe		Undeveloped		Field Expense			Total
Net Reserves
Oil/Condensate-MBbls		201.0		73.6		138.8		608.5		—			1,021.8
Gas-MMCF		969.9		896.7		3,916.5		6,248.2		—			12,031.4
Income Data (M$)
Future Gross Revenue	$	26,914.2	$	11,882.7	$	32,973.7	$	87,513.1	$	—		$	159,283.7
Ad Valorem Tax	$	672.9	$	297.1	$	824.3	$	2,187.8	$	—		$	3,982.1
Severance Tax	$	1,381.6	$	658.1	$	2,033.1	$	4,750.6	$	—		$	8,823.4
Operating Costs	$	351.0	$	258.1	$	1,336.0	$	3,172.4	$	36,514.2		$	41,631.6
Capital Costs	$	-	$	525.0	$	1,575.0	$	14,950.0	$	4,731.1		$	21,781.1
Future Net Income (FNI)	$	24,508.8	$	10,144.5	$	27,205.3	$	62,452.2	$	(41,245.3	)	$	83,065.5
FNI @ 10%	$	17,502.9	$	7,519.6	$	16,465.3	$	32,002.7	$	(21,972.8	)	$	51,517.7

*(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: Errors in addition are due to rounding.

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.

Texas Registered Engineering Firm F-1529

Hydrocarb Energy Corporation	August 21, 2014
SEC Non-Escalated Analysis	Page 3 of 6
Oil, Condensate, and Natural Gas Reserves

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.

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.

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.

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

Hydrocarb Energy Corporation	August 21, 2014
SEC Non-Escalated Analysis	Page 4 of 6
Oil, Condensate, and Natural Gas Reserves

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

Hydrocarb Energy Corporation	August 21, 2014
SEC Non-Escalated Analysis	Page 5 of 6
Oil, Condensate, and Natural Gas Reserves

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 price in effect the first trading of each month from July 2013 through June 2014 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 $100.11 per barrel represents the effective average crude oil price utilized in the evaluation. This scheduled price for 2014 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 $105.39 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 $4.10 per MMBTU represents the effective average natural gas price utilized in the evaluation. The scheduled price for 2014 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 $4.29 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.

Texas Registered Engineering Firm F-1529

Hydrocarb Energy Corporation	August 21, 2014
SEC Non-Escalated Analysis	Page 6 of 6
Oil, Condensate, and Natural Gas Reserves

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.

Very truly yours,

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

Securities and Exchange CommissionDefinitions 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.

(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.

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

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.

     (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.

Securities and Exchange Commission	Page 3
§ 210.4-10 Definitions (of Reserves)
Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter

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.

Certificate of Qualification

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 July 31, 2014.
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-five years of experience in the petroleum industry of which over thirty-five 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: August 21, 2014

1717 St. James Place, Suite 460    Houston, Texas 77056    Office 713-622-8955    Fax 713-626-3664    www.ralphedavis.com

Worldwide Energy Consultants Since 1924

Economic Summary Report

Date :     08/21/2014 11:46:45AM
		ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Total
Partner :	All Cases	Discount Rate (%) :	10.00
Case Type :	GRAND TOTAL CASE	All Cases
		SEC REPORT
Cum Oil (Mbbl) :	4,085.47
Cum Gas (MMcf) :	40,357.72

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	33.20	316.73	26.58	188.97	109.28	4.56	2,904.86	861.68	0.00
2015	88.89	2,140.17	71.26	1,089.85	109.28	4.34	7,787.36	4,732.48	0.00
2016	107.76	2,600.26	81.75	1,505.60	109.30	4.43	8,934.73	6,668.86	0.00
2017	205.96	2,297.98	162.26	1,486.69	103.97	4.32	16,869.87	6,415.07	0.00
2018	178.87	2,718.19	141.40	1,823.43	104.28	4.22	14,745.90	7,687.71	0.00
2019	143.18	1,991.11	113.31	1,316.14	104.17	4.31	11,803.47	5,671.39	0.00
2020	114.70	1,394.81	90.98	912.30	104.04	4.33	9,465.40	3,948.19	0.00
2021	92.04	982.24	73.16	633.16	103.95	4.35	7,604.82	2,751.82	0.00
2022	74.53	700.35	59.37	443.90	103.90	4.36	6,168.08	1,937.31	0.00
2023	48.35	456.24	38.41	310.53	102.46	4.38	3,935.48	1,361.41	0.00
2024	38.82	322.38	30.90	218.87	102.31	4.41	3,161.11	964.42	0.00
2025	36.73	430.11	29.24	298.92	103.56	4.22	3,028.37	1,261.74	0.00
2026	15.85	333.41	12.48	231.69	109.30	4.21	1,363.52	975.89	0.00
2027	37.19	565.71	30.00	402.63	109.29	4.09	3,279.04	1,647.32	0.00
2028	39.62	851.55	31.78	609.75	109.29	4.05	3,473.42	2,466.74	0.00
Rem	35.84	775.90	28.91	558.94	109.29	4.02	3,159.36	2,246.89	0.00
Total	1,291.53	18,877.17	1,021.78	12,031.36	105.39	4.29	107,684.79	51,598.90	0.00
Ult	5,377.00	59,234.89

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	36.00	198.25	94.16	50.00	1,278.65	0.00	78.62	0.00	2,066.87	2,021.86
2015	39.00	713.15	313.00	3,525.00	3,049.09	0.00	372.62	0.00	4,546.98	6,032.98
2016	43.00	911.16	390.09	4,330.51	2,907.86	0.00	525.10	0.00	6,538.86	11,340.64
2017	39.00	1,257.14	582.12	5,300.00	2,807.98	0.00	625.64	0.00	12,712.05	20,818.02
2018	40.00	1,254.89	560.84	3,484.36	2,807.98	0.00	823.71	0.00	13,501.83	29,877.87
2019	40.00	968.31	436.87	0.00	2,807.98	0.00	563.01	0.00	12,698.68	37,679.84
2020	38.00	731.52	335.34	0.00	2,807.98	0.00	388.19	0.00	9,150.56	42,769.07
2021	37.00	556.21	258.92	0.00	2,807.98	0.00	268.46	0.00	6,465.08	46,023.95
2022	37.00	429.03	202.63	0.00	2,807.98	0.00	188.02	0.00	4,477.72	48,065.17
2023	32.00	283.14	132.42	1,442.65	1,749.15	0.00	131.99	0.00	1,557.55	48,694.99
2024	24.00	217.74	103.14	0.00	1,749.15	0.00	93.35	0.00	1,962.15	49,428.44
2025	24.00	233.94	107.25	350.00	1,749.15	0.00	140.95	0.00	1,708.82	50,001.56
2026	19.00	135.91	58.49	50.00	1,749.15	0.00	112.03	0.00	233.84	50,070.13
2027	19.00	274.39	123.16	700.00	1,749.15	0.00	202.20	0.00	1,877.47	50,581.09
2028	15.00	344.78	148.50	0.00	1,749.15	0.00	310.52	0.00	3,387.20	51,433.57
Rem.		313.85	135.16	2,548.59	1,935.79	0.00	293.03	0.00	179.82	84.10
Total		8,823.42	3,982.09	21,781.11	36,514.15	0.00	5,117.44	0.00	83,065.48	51,517.67

		Present Worth Profile (M$)
		PW	5.00% :	64,713.19
Disc. Initial Invest. (M$) :	2,962.01	PW	10.00% :	51,517.67
ROInvestment (disc/undisc) :	18.39 / 20.03	PW	15.00% :	41,771.29
Years to Payout :	1.07	PW	20.00% :	34,401.94
Internal ROR (%) :	>1000	PW	25.00% :	28,717.00
		PW	30.00% :	24,255.83

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

1

Date :     08/21/2014 11:46:45AM
		ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Producing Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00
Case Type :	REPORT BREAK TOTAL CASE	All Cases
		SEC REPORT
Cum Oil (Mbbl) :	2,850.12
Cum Gas (MMcf) :	30,476.83

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	20.71	183.34	16.54	93.24	109.27	5.13	1,807.64	478.13	0.00
2015	45.87	396.83	36.71	186.02	109.28	5.13	4,011.54	954.20	0.00
2016	36.65	322.52	29.55	145.94	109.29	5.13	3,228.99	748.15	0.00
2017	30.40	263.71	24.55	115.11	109.29	5.12	2,682.90	589.78	0.00
2018	26.03	217.08	21.03	91.22	109.29	5.12	2,298.15	466.60	0.00
2019	22.47	178.94	18.16	72.17	109.29	5.10	1,984.75	367.98	0.00
2020	19.53	150.03	15.79	58.26	109.29	5.09	1,725.45	296.65	0.00
2021	16.99	125.73	13.74	47.03	109.29	5.08	1,501.58	238.86	0.00
2022	14.90	106.18	12.05	38.28	109.29	5.06	1,317.48	193.71	0.00
2023	3.71	44.32	2.98	30.14	109.31	5.08	325.75	153.03	0.00
2024	3.09	34.53	2.48	23.38	109.31	5.11	271.12	119.60	0.00
2025	2.54	28.28	2.04	19.20	109.31	5.08	223.54	97.57	0.00
2026	2.17	23.53	1.74	16.03	109.31	5.04	190.68	80.76	0.00
2027	1.81	19.48	1.46	13.31	109.31	5.00	159.61	66.53	0.00
2028	1.33	15.40	1.07	10.51	109.31	5.02	116.81	52.70	0.00
Rem	1.33	14.15	1.09	10.11	109.29	4.44	118.96	44.94	0.00
Total	249.52	2,124.05	200.98	969.94	109.29	5.10	21,964.96	4,949.21	0.00
Ult	3,099.63	32,600.87

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	15.00	119.01	57.14	0.00	0.00	0.00	26.90	0.00	2,082.72	2,038.00
2015	15.00	256.10	124.14	0.00	0.00	0.00	54.28	0.00	4,531.22	6,181.13
2016	15.00	204.65	99.43	0.00	0.00	0.00	44.01	0.00	3,629.06	9,184.15
2017	12.00	167.65	81.82	0.00	0.00	0.00	36.14	0.00	2,987.07	11,420.89
2018	11.00	140.71	69.12	0.00	0.00	0.00	30.24	0.00	2,524.68	13,132.17
2019	11.00	118.90	58.82	0.00	0.00	0.00	25.66	0.00	2,149.36	14,450.92
2020	10.00	101.62	50.55	0.00	0.00	0.00	21.94	0.00	1,847.98	15,477.19
2021	10.00	86.99	43.51	0.00	0.00	0.00	18.97	0.00	1,590.98	16,276.87
2022	10.00	75.13	37.78	0.00	0.00	0.00	16.65	0.00	1,381.63	16,905.52
2023	6.00	26.46	11.97	0.00	0.00	0.00	14.15	0.00	426.20	17,081.19
2024	4.00	21.44	9.77	0.00	0.00	0.00	11.95	0.00	347.55	17,210.85
2025	4.00	17.60	8.03	0.00	0.00	0.00	10.72	0.00	284.76	17,306.98
2026	4.00	14.83	6.79	0.00	0.00	0.00	9.79	0.00	240.04	17,380.33
2027	3.00	12.33	5.65	0.00	0.00	0.00	8.86	0.00	199.30	17,435.51
2028	3.00	9.33	4.24	0.00	0.00	0.00	7.63	0.00	148.31	17,472.65
Rem.		8.84	4.10	0.00	0.00	0.00	13.05	0.00	137.90	30.22
Total		1,381.58	672.85	0.00	0.00	0.00	350.96	0.00	24,508.77	17,502.87

		Present Worth Profile (M$)
		PW	5.00% :	20,496.95
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	17,502.87
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	15,209.56
Years to Payout :	0.00	PW	20.00% :	13,412.41
Internal ROR (%) :	0.00	PW	25.00% :	11,975.48
		PW	30.00% :	10,806.00

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

2

Date :     08/21/2014 11:46:45AM
		ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Shut-In Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00
Case Type :	REPORT BREAK TOTAL CASE	All Cases
		SEC REPORT
Cum Oil (Mbbl) :	1,229.87
Cum Gas (MMcf) :	9,766.76

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	7.18	22.75	5.82	16.65	109.29	4.04	636.26	67.22	0.00
2015	17.40	901.18	14.14	360.58	109.29	4.45	1,545.73	1,605.30	0.00
2016	14.98	564.73	12.20	245.58	109.29	4.38	1,333.72	1,074.64	0.00
2017	12.05	79.98	9.81	59.92	109.29	4.01	1,071.90	240.36	0.00
2018	9.85	61.82	8.02	46.31	109.29	4.01	876.07	185.74	0.00
2019	8.18	50.12	6.65	37.52	109.29	4.01	727.14	150.47	0.00
2020	6.81	40.77	5.54	30.50	109.29	4.01	605.68	122.30	0.00
2021	5.62	32.94	4.57	24.63	109.29	4.00	499.89	98.66	0.00
2022	4.66	26.72	3.79	19.97	109.29	4.00	414.10	79.88	0.00
2023	0.94	21.75	0.77	16.25	109.29	4.00	84.11	64.99	0.00
2024	0.77	17.77	0.63	13.26	109.29	4.00	68.71	53.06	0.00
2025	0.59	12.44	0.48	9.29	109.29	4.00	52.76	37.14	0.00
2026	0.43	7.54	0.35	5.58	109.29	4.00	38.40	22.32	0.00
2027	0.35	6.08	0.29	4.49	109.29	4.00	31.32	17.98	0.00
2028	0.28	4.68	0.23	3.44	109.29	4.00	24.80	13.77	0.00
Rem	0.32	3.81	0.25	2.72	109.29	4.00	27.45	10.89	0.00
Total	90.43	1,855.09	73.55	896.71	109.29	4.29	8,038.02	3,844.71	0.00
Ult	1,320.30	11,621.85

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	10.00	34.31	17.59	50.00	0.00	0.00	10.98	0.00	590.59	577.61
2015	10.00	191.50	78.78	475.00	0.00	0.00	39.36	0.00	2,366.40	2,716.25
2016	10.00	141.95	60.21	0.00	0.00	0.00	45.49	0.00	2,160.71	4,509.25
2017	8.00	67.33	32.81	0.00	0.00	0.00	34.64	0.00	1,177.47	5,391.47
2018	8.00	54.23	26.55	0.00	0.00	0.00	27.03	0.00	954.00	6,038.24
2019	8.00	44.73	21.94	0.00	0.00	0.00	21.98	0.00	788.95	6,522.44
2020	8.00	37.03	18.20	0.00	0.00	0.00	17.93	0.00	654.81	6,886.19
2021	7.00	30.39	14.96	0.00	0.00	0.00	14.56	0.00	538.62	7,157.06
2022	7.00	25.04	12.35	0.00	0.00	0.00	11.87	0.00	444.72	7,359.49
2023	7.00	8.74	3.73	0.00	0.00	0.00	9.69	0.00	126.94	7,411.80
2024	4.00	7.14	3.04	0.00	0.00	0.00	7.93	0.00	103.65	7,450.47
2025	3.00	5.21	2.25	0.00	0.00	0.00	5.71	0.00	76.73	7,476.38
2026	2.00	3.44	1.52	0.00	0.00	0.00	3.57	0.00	52.19	7,492.35
2027	2.00	2.79	1.23	0.00	0.00	0.00	2.89	0.00	42.38	7,504.07
2028	1.00	2.17	0.96	0.00	0.00	0.00	2.26	0.00	33.17	7,512.40
Rem.		2.08	0.96	0.00	0.00	0.00	2.16	0.00	33.14	7.21
Total		658.10	297.07	525.00	0.00	0.00	258.06	0.00	10,144.50	7,519.61

		Present Worth Profile (M$)
		PW	5.00% :	8,664.02
Disc. Initial Invest. (M$) :	306.58	PW	10.00% :	7,519.61
ROInvestment (disc/undisc) :	25.53 / 32.21	PW	15.00% :	6,614.44
Years to Payout :	0.26	PW	20.00% :	5,883.98
Internal ROR (%) :	>1000	PW	25.00% :	5,284.11
		PW	30.00% :	4,783.87

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

3

Date :     08/21/2014 11:46:45AM
		ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Behind Pipe Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00
Case Type :	REPORT BREAK TOTAL CASE	All Cases
		SEC REPORT
Cum Oil (Mbbl) :	5.48
Cum Gas (MMcf) :	114.14

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	5.31	110.65	4.22	79.08	109.29	4.00	460.96	316.34	0.00
2015	13.11	473.97	10.46	280.08	109.29	4.00	1,143.56	1,120.32	0.00
2016	29.69	925.96	19.00	551.54	109.32	4.71	2,076.96	2,595.89	0.00
2017	25.75	1,240.11	16.36	798.19	109.32	4.42	1,788.12	3,529.47	0.00
2018	20.76	1,075.60	13.48	704.22	109.32	4.41	1,474.07	3,107.35	0.00
2019	15.56	805.31	10.02	517.54	109.32	4.63	1,095.08	2,396.26	0.00
2020	10.93	531.03	6.95	338.80	109.32	4.69	760.06	1,589.43	0.00
2021	7.72	352.61	4.86	222.15	109.33	4.75	531.17	1,056.21	0.00
2022	5.49	236.64	3.42	147.19	109.33	4.82	374.36	709.30	0.00
2023	3.90	157.68	2.40	96.48	109.33	4.89	262.57	472.24	0.00
2024	2.79	106.21	1.71	63.98	109.33	4.98	186.63	318.39	0.00
2025	1.99	72.54	1.21	43.15	109.33	5.04	132.11	217.59	0.00
2026	5.74	49.87	4.41	29.31	109.30	5.11	481.84	149.74	0.00
2027	21.35	36.36	17.36	21.49	109.29	5.09	1,897.47	109.46	0.00
2028	13.98	24.84	11.35	14.44	109.29	5.18	1,240.40	74.81	0.00
Rem	14.11	14.01	11.56	8.83	109.29	4.75	1,263.61	41.96	0.00
Total	198.18	6,213.39	138.77	3,916.48	109.31	4.55	15,168.96	17,804.75	0.00
Ult	203.65	6,327.53

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	3.00	44.93	19.43	0.00	0.00	0.00	40.74	0.00	672.20	658.32
2015	5.00	136.63	56.60	550.00	0.00	0.00	143.42	0.00	1,377.24	1,901.22
2016	8.00	290.23	116.82	390.63	0.00	0.00	145.81	0.00	3,729.35	4,966.62
2017	9.00	346.96	132.94	300.00	0.00	0.00	298.82	0.00	4,238.86	8,125.19
2018	10.00	300.86	114.54	284.36	0.00	0.00	268.88	0.00	3,612.78	10,579.75
2019	10.00	230.09	87.28	0.00	0.00	0.00	167.00	0.00	3,006.96	12,428.38
2020	9.00	154.17	58.74	0.00	0.00	0.00	103.84	0.00	2,032.74	13,559.45
2021	9.00	103.65	39.68	0.00	0.00	0.00	64.31	0.00	1,379.74	14,254.30
2022	9.00	70.42	27.09	0.00	0.00	0.00	40.04	0.00	946.11	14,685.62
2023	9.00	47.50	18.37	0.00	0.00	0.00	24.50	0.00	644.44	14,951.61
2024	7.00	32.46	12.63	0.00	0.00	0.00	14.76	0.00	445.17	15,117.88
2025	7.00	22.40	8.74	0.00	0.00	0.00	9.14	0.00	309.41	15,222.51
2026	5.00	33.40	15.79	50.00	0.00	0.00	5.63	0.00	526.76	15,379.40
2027	4.00	95.49	50.17	0.00	0.00	0.00	4.15	0.00	1,857.12	15,894.25
2028	3.00	62.67	32.88	0.00	0.00	0.00	2.43	0.00	1,217.23	16,199.67
Rem.		61.27	32.64	0.00	0.00	0.00	2.53	0.00	1,209.13	265.58
Total		2,033.13	824.34	1,574.99	0.00	0.00	1,336.00	0.00	27,205.25	16,465.26

		Present Worth Profile (M$)
		PW	5.00% :	20,778.48
Disc. Initial Invest. (M$) :	378.43	PW	10.00% :	16,465.26
ROInvestment (disc/undisc) :	44.51 / 56.45	PW	15.00% :	13,425.88
Years to Payout :	0.31	PW	20.00% :	11,191.41
Internal ROR (%) :	>1000	PW	25.00% :	9,490.01
		PW	30.00% :	8,157.50

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

4

Date :     08/21/2014 11:46:45AM
		ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Undeveloped Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00
Case Type :	REPORT BREAK TOTAL CASE	All Cases
		SEC REPORT
Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	12.52	368.19	9.94	263.16	109.29	4.00	1,086.53	1,052.65	0.00
2016	26.44	787.05	21.00	562.54	109.29	4.00	2,295.06	2,250.18	0.00
2017	137.77	714.17	111.54	513.47	101.55	4.00	11,326.96	2,055.46	0.00
2018	122.23	1,363.69	98.87	981.68	102.13	4.00	10,097.62	3,928.01	0.00
2019	96.97	956.73	78.48	688.90	101.89	4.00	7,996.50	2,756.68	0.00
2020	77.43	672.98	62.69	484.73	101.67	4.00	6,374.22	1,939.81	0.00
2021	61.71	470.97	49.98	339.34	101.48	4.00	5,072.18	1,358.09	0.00
2022	49.48	330.82	40.10	238.46	101.30	4.00	4,062.13	954.42	0.00
2023	39.80	232.50	32.26	167.67	101.15	4.00	3,263.05	671.15	0.00
2024	32.17	163.87	26.08	118.24	101.01	4.00	2,634.66	473.37	0.00
2025	31.59	316.85	25.51	227.28	102.72	4.00	2,619.96	909.44	0.00
2026	7.51	252.47	5.97	180.77	109.29	4.00	652.60	723.06	0.00
2027	13.67	503.79	10.89	363.34	109.29	4.00	1,190.63	1,453.35	0.00
2028	24.03	806.64	19.14	581.37	109.29	4.00	2,091.41	2,325.46	0.00
Rem	20.08	743.93	16.01	537.28	109.29	4.00	1,749.34	2,149.10	0.00
Total	753.41	8,684.64	608.47	6,248.23	102.74	4.00	62,512.85	25,000.24	0.00
Ult	753.41	8,684.64

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	128.93	53.48	2,500.00	0.00	0.00	135.56	0.00	-678.79	-730.23
2016	2.00	274.34	113.63	3,200.00	0.00	0.00	289.78	0.00	667.49	-278.32
2017	4.00	675.20	334.56	5,000.00	0.00	0.00	256.04	0.00	7,116.62	5,021.57
2018	5.00	759.09	350.64	3,200.00	0.00	0.00	497.55	0.00	9,218.35	11,169.93
2019	5.00	574.59	268.83	0.00	0.00	0.00	348.37	0.00	9,561.38	17,041.34
2020	5.00	438.70	207.85	0.00	0.00	0.00	244.48	0.00	7,423.00	21,167.09
2021	5.00	335.18	160.76	0.00	0.00	0.00	170.62	0.00	5,763.72	24,066.61
2022	5.00	258.44	125.41	0.00	0.00	0.00	119.46	0.00	4,513.24	26,121.90
2023	5.00	200.44	98.36	0.00	0.00	0.00	83.64	0.00	3,551.77	27,586.08
2024	5.00	156.70	77.70	0.00	0.00	0.00	58.70	0.00	2,814.94	28,636.40
2025	6.00	188.73	88.24	350.00	0.00	0.00	115.38	0.00	2,787.06	29,572.60
2026	4.00	84.25	34.39	0.00	0.00	0.00	93.03	0.00	1,163.99	29,928.84
2027	6.00	163.77	66.10	700.00	0.00	0.00	186.30	0.00	1,527.81	30,341.36
2028	4.00	270.61	110.42	0.00	0.00	0.00	298.20	0.00	3,737.64	31,280.37
Rem.		241.65	97.46	0.00	0.00	0.00	275.29	0.00	3,284.03	722.34
Total		4,750.61	2,187.83	14,950.00	0.00	0.00	3,172.42	0.00	62,452.23	32,002.71

		Present Worth Profile (M$)
		PW	5.00% :	44,108.92
Disc. Initial Invest. (M$) :	2,277.00	PW	10.00% :	32,002.71
ROInvestment (disc/undisc) :	15.05 / 18.59	PW	15.00% :	23,721.41
Years to Payout :	2.70	PW	20.00% :	17,876.08
Internal ROR (%) :	92.34	PW	25.00% :	13,638.54
		PW	30.00% :	10,497.21

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

5

Date :     08/21/2014 11:46:45AM
		ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Field Expense Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00
Case Type :	REPORT BREAK TOTAL CASE	All Cases
		SEC REPORT
Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2028	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	8.00	0.00	0.00	0.00	1,278.65	0.00	0.00	0.00	-1,278.65	-1,252.07
2015	8.00	0.00	0.00	0.00	3,049.09	0.00	0.00	0.00	-3,049.09	-4,035.38
2016	8.00	0.00	0.00	739.88	2,907.86	0.00	0.00	0.00	-3,647.75	-7,041.05
2017	6.00	0.00	0.00	0.00	2,807.98	0.00	0.00	0.00	-2,807.98	-9,141.10
2018	6.00	0.00	0.00	0.00	2,807.98	0.00	0.00	0.00	-2,807.98	-11,042.21
2019	6.00	0.00	0.00	0.00	2,807.98	0.00	0.00	0.00	-2,807.98	-12,763.24
2020	6.00	0.00	0.00	0.00	2,807.98	0.00	0.00	0.00	-2,807.98	-14,320.86
2021	6.00	0.00	0.00	0.00	2,807.98	0.00	0.00	0.00	-2,807.98	-15,730.89
2022	6.00	0.00	0.00	0.00	2,807.98	0.00	0.00	0.00	-2,807.98	-17,007.36
2023	5.00	0.00	0.00	1,442.65	1,749.15	0.00	0.00	0.00	-3,191.80	-18,335.70
2024	4.00	0.00	0.00	0.00	1,749.15	0.00	0.00	0.00	-1,749.15	-18,987.17
2025	4.00	0.00	0.00	0.00	1,749.15	0.00	0.00	0.00	-1,749.15	-19,576.91
2026	4.00	0.00	0.00	0.00	1,749.15	0.00	0.00	0.00	-1,749.15	-20,110.79
2027	4.00	0.00	0.00	0.00	1,749.15	0.00	0.00	0.00	-1,749.15	-20,594.10
2028	4.00	0.00	0.00	0.00	1,749.15	0.00	0.00	0.00	-1,749.15	-21,031.52
Rem.		0.00	0.00	2,548.59	1,935.79	0.00	0.00	0.00	-4,484.38	-941.26
Total		0.00	0.00	4,731.12	36,514.15	0.00	0.00	0.00	-41,245.27	-21,972.78

		Present Worth Profile (M$)
		PW	5.00% :	-29,335.17
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-21,972.78
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-17,199.99
Years to Payout :	0.00	PW	20.00% :	-13,961.94
Internal ROR (%) :	0.00	PW	25.00% :	-11,671.15
		PW	30.00% :	-9,988.75

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

6

One-line Summary

Sorted by Reserve Category,

Field, and Lease

8/21/2014       11:48:10AM	Economic One-Liners
Project Name :         HYDROCARB ENERGY 06/30/2014	As of Date: 7/31/2014
Ownership Group : All Cases	SEC REPORT

	Gross Reserves		Net Reserves		Net Revenue			Expense		Cash Flow
Lease Name	Oil	Gas	Oil	Gas	Oil	Gas	Other	& Tax	Invest.	Non-Disc.	Disc. 10%
Risked / UnRisked	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Grand Total	1,291.53	18,877.17	1,021.78	12,031.36	107,684.79	51,598.90	0.00	54,437.10	21,781.11	83,065.48	51,517.67
Proved Producing Rsv Class & Category	249.52	2,124.05	200.98	969.94	21,964.96	4,949.21	0.00	2,405.39	0.00	24,508.77	17,502.87
Proved Producing Rsv Class & Category
FISHERS REEF Field	58.39	930.61	45.02	596.06	4,922.09	3,453.68	0.00	694.84	0.00	7,680.94	5,492.36
FRSU #1 115 (06384) - GBE	35.21	125.90	28.54	88.77	3,120.17	514.38	0.00	272.97	0.00	3,361.58	2,370.39
ST 02-3A #001 (23530) - GBE	20.87	763.65	15.18	483.19	1,659.86	2,799.71	0.00	397.82	0.00	4,061.75	2,888.81
ST 05-8A (230143) #01 - GBE	0.03	36.26	0.02	21.74	2.49	125.99	0.00	12.78	0.00	115.71	100.83
ST 06-7A #01 ST (25088) - GBE	2.27	4.80	1.28	2.35	139.57	13.60	0.00	11.27	0.00	141.90	132.32
Proved Producing Rsv Class & Category
POINT BOLIVAR NORTH Field	0.10	0.00	0.07	0.00	5.98	0.00	0.00	0.42	0.00	5.56	5.11
ST 343 18 (18424) A-1a Thru	0.10	0.00	0.07	0.00	5.98	0.00	0.00	0.42	0.00	5.56	5.11
Proved Producing Rsv Class & Category
RED FISH REEF Field	50.83	499.64	41.99	373.88	4,589.48	1,495.52	0.00	826.37	0.00	5,258.64	3,625.57
RFRU 224 185 (099996) - GBE	0.75	2.23	0.63	1.70	69.20	6.80	0.00	6.60	0.00	69.40	48.88
ST 224 141U (052698) - GBE	0.86	161.58	0.73	122.88	79.33	491.53	0.00	115.80	0.00	455.05	358.91
ST 225 139 (23981) - GBE	3.23	10.72	2.73	8.15	298.00	32.61	0.00	36.45	0.00	294.15	255.82
ST 246 120 (06840) - GBE	18.59	188.23	15.32	139.62	1,674.52	558.47	0.00	382.95	0.00	1,850.03	1,061.91
ST 246 183 (096910) - GBE	8.54	35.95	7.04	26.67	769.48	106.67	0.00	81.64	0.00	794.50	636.90
ST 247 188 (102549) - GBE (1)	18.86	100.93	15.55	74.86	1,698.96	299.45	0.00	202.92	0.00	1,795.50	1,263.15
Proved Producing Rsv Class & Category
TRINITY BAY Field	140.20	693.79	113.90	0.00	12,447.41	0.00	0.00	883.77	0.00	11,563.64	8,379.83
TBSU #1 (08444) #37 - GBE	4.80	0.00	3.90	0.00	426.05	0.00	0.00	30.25	0.00	395.80	368.65
TBSU #1 013 (16366) - GBE	36.49	198.29	29.65	0.00	3,240.04	0.00	0.00	230.04	0.00	3,010.00	2,132.76
TBSU #1 12, 35, 130 (8004) -	47.45	294.69	38.55	0.00	4,212.72	0.00	0.00	299.10	0.00	3,913.62	2,873.24
TBSU #1 69D, 75F, 135 (5351	51.46	200.81	41.81	0.00	4,568.60	0.00	0.00	324.37	0.00	4,244.23	3,005.18
Proved Shut-In Rsv Class & Category	90.43	1,855.09	73.55	896.71	8,038.02	3,844.71	0.00	1,213.23	525.00	10,144.50	7,519.61
Proved Shut-In Rsv Class & Category
FISHERS REEF Field	1.33	3.67	1.08	2.59	117.91	14.98	0.00	9.87	0.00	123.02	98.53
RFRU 1 112 (12528) - GBE	1.33	3.67	1.08	2.59	117.91	14.98	0.00	9.87	0.00	123.02	98.53

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

7

8/21/2014       11:48:10AM	Economic One-Liners
Project Name :         HYDROCARB ENERGY 06/30/2014	As of Date: 7/31/2014
Ownership Group : All Cases	SEC REPORT

	Gross Reserves		Net Reserves		Net Revenue			Expense		Cash Flow
Lease Name	Oil	Gas	Oil	Gas	Oil	Gas	Other	& Tax	Invest.	Non-Disc.	Disc. 10%
Risked / UnRisked	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Proved Shut-In Rsv Class & Category
POINT BOLIVAR NORTH Field	0.00	1,269.53	0.00	459.57	0.00	2,091.51	0.00	209.15	325.00	1,557.36	1,349.47
ST 343 1 (Big Gas) - GBE	0.00	1,269.53	0.00	459.57	0.00	2,091.51	0.00	209.15	325.00	1,557.36	1,349.47
Proved Shut-In Rsv Class & Category
RED FISH REEF Field	28.06	581.89	22.88	434.56	2,500.56	1,738.22	0.00	609.43	150.00	3,479.35	2,384.04
RFRU 247 21 (08946) - GBE	14.15	117.00	11.24	83.63	1,227.94	334.51	0.00	197.97	0.00	1,364.48	912.47
ST 224 176 - GBE	2.42	121.00	2.04	92.02	223.48	368.08	0.00	103.51	50.00	438.05	277.26
ST 225 050 - GBE	6.13	204.35	5.18	155.41	566.16	621.64	0.00	179.94	50.00	957.86	620.07
ST 247 175-L - GBE	2.39	87.39	1.97	64.82	215.35	259.28	0.00	73.98	50.00	350.64	239.39
ST 247 198 (190463) F 10 Str	2.97	52.15	2.45	38.68	267.63	154.72	0.00	54.02	0.00	368.32	334.86
Proved Shut-In Rsv Class & Category
TRINITY BAY Field	61.04	0.00	49.59	0.00	5,419.56	0.00	0.00	384.79	50.00	4,984.77	3,687.57
TBSU #1 063D - GBE	27.31	0.00	22.19	0.00	2,425.32	0.00	0.00	172.20	0.00	2,253.12	1,668.57
TBSU #1 068 - GBE	13.82	0.00	11.23	0.00	1,227.16	0.00	0.00	87.13	0.00	1,140.03	868.81
TBSU #1 133 - GBE	19.90	0.00	16.17	0.00	1,767.08	0.00	0.00	125.46	50.00	1,591.62	1,150.19
Proved Behind Pipe Rsv Class & Category	198.18	6,213.39	138.77	3,916.48	15,168.96	17,804.75	0.00	4,193.47	1,574.99	27,205.25	16,465.26
Proved Behind Pipe Rsv Class & Category
FISHERS REEF Field	91.92	2,233.43	52.25	1,145.74	5,713.11	6,638.64	0.00	1,069.49	424.99	10,857.26	6,805.56
ST 05-8A #01 (BP02) - GBE	4.94	493.76	3.40	295.72	371.65	1,713.43	0.00	197.73	284.36	1,602.99	800.33
ST 06-7A #01 ST F-13 - GBE	86.98	1,739.67	48.85	850.02	5,341.46	4,925.20	0.00	871.76	140.63	9,254.27	6,005.22
Proved Behind Pipe Rsv Class & Category
RED FISH REEF Field	99.20	3,627.23	80.79	2,619.85	8,829.51	10,479.39	0.00	3,010.83	850.00	15,448.07	9,010.41
ST 225 187 - GBE	3.12	496.03	2.55	363.84	278.35	1,455.34	0.00	350.25	250.00	1,133.44	862.57
ST 246 181 (BP01) - GBE	31.28	651.72	24.84	465.81	2,715.14	1,863.26	0.00	619.05	0.00	3,959.34	3,295.93
ST 247 023 (BP01) - GBE	0.02	1,073.08	0.01	766.98	1.37	3,067.93	0.00	701.99	250.00	2,117.32	1,320.18
ST 247 198 (190463) F 7A &	51.89	25.95	42.77	19.24	4,673.91	76.98	0.00	349.03	50.00	4,351.86	1,113.57
ST 247 198 (190463) F 9 - GBE	12.89	640.00	10.62	474.72	1,160.75	1,898.88	0.00	506.18	50.00	2,503.45	1,509.06
ST 247 21 (BP01) - GBE	0.00	740.47	0.00	529.25	0.00	2,116.99	0.00	484.33	250.00	1,382.66	909.11
Proved Behind Pipe Rsv Class & Category
TRINITY BAY Field	7.05	352.73	5.73	150.90	626.33	686.72	0.00	113.14	300.00	899.91	649.29

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

8

8/21/2014       11:48:10AM	Economic One-Liners
Project Name :         HYDROCARB ENERGY 06/30/2014	As of Date: 7/31/2014
Ownership Group : All Cases	SEC REPORT

	Gross Reserves		Net Reserves		Net Revenue			Expense		Cash Flow
Lease Name	Oil	Gas	Oil	Gas	Oil	Gas	Other	& Tax	Invest.	Non-Disc.	Disc. 10%
Risked / UnRisked	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
TBSU #1 053 - GBE	3.34	167.00	2.71	0.00	296.54	0.00	0.00	21.05	250.00	25.48	-5.34
TBSU #1 135 - GBE	3.71	185.73	3.02	150.90	329.80	686.72	0.00	92.09	50.00	874.43	654.63
Proved Undeveloped Rsv Class & Category	753.41	8,684.64	608.47	6,248.23	62,512.85	25,000.24	0.00	10,110.85	14,950.00	62,452.23	32,002.71
Proved Undeveloped Rsv Class & Category
RED FISH REEF Field	218.79	8,594.52	174.12	6,175.01	19,030.10	24,700.05	0.00	6,993.56	12,450.00	24,286.60	10,136.73
ST 224 ACW #15L - GBE	10.69	989.70	8.71	725.94	952.06	2,903.77	0.00	727.01	2,500.00	628.82	-2.35
ST 224 ACW #15U - GBE	7.21	721.42	5.88	529.16	642.58	2,116.64	0.00	526.29	350.00	1,882.93	443.78
ST 246 ACW #35L - GBE	40.61	1,194.36	32.25	853.67	3,524.56	3,414.66	0.00	1,031.46	2,500.00	3,407.76	2,109.77
ST 246 ACW #35U - GBE	24.26	713.56	19.27	510.02	2,105.72	2,040.07	0.00	616.24	350.00	3,179.56	901.33
ST 246 ACW #40L - GBE	67.24	2,013.04	53.40	1,438.82	5,835.67	5,755.28	0.00	1,731.04	3,200.00	6,659.91	3,923.90
ST 246 ACW #40U - GBE	38.38	936.19	30.48	669.14	3,331.50	2,676.57	0.00	848.89	350.00	4,809.18	1,162.06
ST 247 119 OFFSET - GBE	30.39	2,026.26	24.14	1,448.27	2,638.02	5,793.07	0.00	1,512.65	3,200.00	3,718.44	1,598.24
Proved Undeveloped Rsv Class & Category
TRINITY BAY Field	534.62	90.12	434.35	73.22	43,482.74	300.19	0.00	3,117.29	2,500.00	38,165.64	21,865.98
ST 25-A NO 01	534.62	90.12	434.35	73.22	43,482.74	300.19	0.00	3,117.29	2,500.00	38,165.64	21,865.98
Field Expense Rsv Class & Category	0.00	0.00	0.00	0.00	0.00	0.00	0.00	36,514.15	4,731.12	-41,245.27	-21,972.78
Field Expense Rsv Class & Category
FISHERS REEF Field	0.00	0.00	0.00	0.00	0.00	0.00	0.00	14,868.04	890.34	-15,758.38	-7,939.30
FIELD ABANDONMENT EX	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	890.34	-890.34	-196.54
FIELD FIXED OPERATING	0.00	0.00	0.00	0.00	0.00	0.00	0.00	14,868.04	0.00	-14,868.04	-7,742.77
Field Expense Rsv Class & Category
POINT BOLIVAR NORTH Field	0.00	0.00	0.00	0.00	0.00	0.00	0.00	442.10	739.88	-1,181.99	-1,004.93
FIELD ABANDONMENT EX	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	739.88	-739.88	-600.92
FIELD FIXED OPERATING	0.00	0.00	0.00	0.00	0.00	0.00	0.00	442.10	0.00	-442.10	-404.01
Field Expense Rsv Class & Category
RED FISH REEF Field	0.00	0.00	0.00	0.00	0.00	0.00	0.00	12,289.32	1,658.25	-13,947.57	-6,385.83
FIELD ABANDONMENT EX	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	1,658.25	-1,658.25	-318.01
FIELD FIXED OPERATING	0.00	0.00	0.00	0.00	0.00	0.00	0.00	12,289.32	0.00	-12,289.32	-6,067.83

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

9

8/21/2014       11:48:10AM	Economic One-Liners
Project Name :         HYDROCARB ENERGY 06/30/2014	As of Date: 7/31/2014
Ownership Group : All Cases	SEC REPORT

	Gross Reserves		Net Reserves		Net Revenue			Expense		Cash Flow
Lease Name	Oil	Gas	Oil	Gas	Oil	Gas	Other	& Tax	Invest.	Non-Disc.	Disc. 10%
Risked / UnRisked	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Field Expense Rsv Class & Category
TRINITY BAY Field	0.00	0.00	0.00	0.00	0.00	0.00	0.00	8,914.68	1,442.65	-10,357.33	-6,642.71
FIELD ABANDONMENT EX	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	1,442.65	-1,442.65	-608.52
FIELD FIXED OPERATING	0.00	0.00	0.00	0.00	0.00	0.00	0.00	8,914.68	0.00	-8,914.68	-6,034.19

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

10

Proved Producing
Economic Detailed Report

Date :     08/21/2014 11:45:32AM
ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Producing Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00	FISHERS REEF Field
Case Type :	REPORT BREAK TOTAL CASE	All Cases
SEC REPORT
Cum Oil (Mbbl) :	1,061.99
Cum Gas (MMcf) :	1,997.59

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	5.38	92.07	4.01	58.62	109.34	5.79	438.78	339.67	0.00
2015	11.94	183.69	9.02	117.11	109.34	5.79	985.78	678.56	0.00
2016	8.71	143.12	6.75	91.62	109.34	5.79	737.91	530.85	0.00
2017	6.83	112.46	5.33	72.09	109.34	5.79	582.67	417.69	0.00
2018	5.49	88.35	4.28	56.70	109.34	5.79	468.24	328.54	0.00
2019	4.41	68.75	3.44	44.20	109.34	5.79	376.21	256.13	0.00
2020	3.55	55.14	2.77	35.46	109.34	5.79	303.14	205.44	0.00
2021	2.85	43.99	2.22	28.28	109.34	5.79	242.93	163.87	0.00
2022	2.29	35.19	1.79	22.63	109.34	5.79	195.27	131.12	0.00
2023	1.84	28.16	1.44	18.11	109.34	5.79	156.97	104.91	0.00
2024	1.48	22.59	1.16	14.52	109.34	5.79	126.49	84.15	0.00
2025	1.19	18.02	0.93	11.58	109.34	5.79	101.37	67.12	0.00
2026	0.95	14.42	0.75	9.27	109.34	5.79	81.49	53.71	0.00
2027	0.77	11.53	0.60	7.42	109.34	5.79	65.50	42.97	0.00
2028	0.61	9.25	0.48	5.95	109.34	5.79	52.08	34.47	0.00
Rem	0.09	3.89	0.07	2.50	109.34	5.79	7.25	14.47	0.00
Total	58.39	930.61	45.02	596.06	109.34	5.79	4,922.09	3,453.68	0.00
Ult	1,120.38	2,928.21

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	4.00	45.66	19.46	0.00	0.00	0.00	0.00	0.00	713.33	698.18
2015	4.00	96.24	41.61	0.00	0.00	0.00	0.00	0.00	1,526.49	2,094.01
2016	4.00	73.76	31.72	0.00	0.00	0.00	0.00	0.00	1,163.29	3,057.13
2017	3.00	58.13	25.01	0.00	0.00	0.00	0.00	0.00	917.23	3,744.23
2018	2.00	46.18	19.92	0.00	0.00	0.00	0.00	0.00	730.68	4,239.79
2019	2.00	36.52	15.81	0.00	0.00	0.00	0.00	0.00	580.02	4,595.85
2020	2.00	29.35	12.71	0.00	0.00	0.00	0.00	0.00	466.51	4,855.07
2021	2.00	23.47	10.17	0.00	0.00	0.00	0.00	0.00	373.17	5,042.76
2022	2.00	18.82	8.16	0.00	0.00	0.00	0.00	0.00	299.42	5,179.09
2023	2.00	15.09	6.55	0.00	0.00	0.00	0.00	0.00	240.24	5,278.11
2024	2.00	12.13	5.27	0.00	0.00	0.00	0.00	0.00	193.24	5,350.21
2025	2.00	9.70	4.21	0.00	0.00	0.00	0.00	0.00	154.58	5,402.41
2026	2.00	7.78	3.38	0.00	0.00	0.00	0.00	0.00	124.04	5,440.33
2027	2.00	6.24	2.71	0.00	0.00	0.00	0.00	0.00	99.53	5,467.87
2028	2.00	4.98	2.16	0.00	0.00	0.00	0.00	0.00	79.41	5,487.77
Rem.		1.42	0.54	0.00	0.00	0.00	0.00	0.00	19.76	4.59
Total		485.44	209.39	0.00	0.00	0.00	0.00	0.00	7,680.94	5,492.36

		Present Worth Profile (M$)
		PW	5.00% :	6,417.89
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	5,492.36
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	4,792.62
Years to Payout :	0.00	PW	20.00% :	4,248.63
Internal ROR (%) :	0.00	PW	25.00% :	3,815.25
		PW	30.00% :	3,462.59

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

11

Date :      08/21/2014 11:45:32 AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	FRSU #1 115 (06384) - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Producing
Case Type :	LEASE CASE	All Cases		Field	:	FISHERS REEF
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:
Cum Oil (Mbbl) :	203.64			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	411.24

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	2.69	11.73	2.18	8.27	109.34	5.79	237.94	47.90	0.00
2015	6.64	23.76	5.38	16.75	109.34	5.79	588.64	97.06	0.00
2016	5.37	19.05	4.35	13.44	109.34	5.79	475.44	77.85	0.00
2017	4.31	15.20	3.49	10.72	109.34	5.79	381.91	62.10	0.00
2018	3.47	12.16	2.81	8.57	109.34	5.79	307.71	49.68	0.00
2019	2.80	9.73	2.27	6.86	109.34	5.79	247.93	39.75	0.00
2020	2.26	7.80	1.83	5.50	109.34	5.79	200.25	31.89	0.00
2021	1.82	6.23	1.47	4.39	109.34	5.79	160.85	25.43	0.00
2022	1.46	4.98	1.19	3.51	109.34	5.79	129.60	20.35	0.00
2023	1.18	3.99	0.96	2.81	109.34	5.79	104.42	16.28	0.00
2024	0.95	3.20	0.77	2.25	109.34	5.79	84.34	13.06	0.00
2025	0.76	2.55	0.62	1.80	109.34	5.79	67.75	10.42	0.00
2026	0.62	2.04	0.50	1.44	109.34	5.79	54.59	8.34	0.00
2027	0.50	1.63	0.40	1.15	109.34	5.79	43.98	6.67	0.00
2028	0.39	1.31	0.32	0.92	109.34	5.79	34.82	5.35	0.00
Rem	0.00	0.55	0.00	0.39	0.00	5.79	0.00	2.25	0.00
Total	35.21	125.90	28.54	88.77	109.34	5.79	3,120.17	514.38	0.00
Ult	238.85	537.15

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	14.54	7.15	0.00	0.00	0.00	0.00	0.00	264.16	258.19
2015	1.00	34.36	17.14	0.00	0.00	0.00	0.00	0.00	634.20	838.01
2016	1.00	27.71	13.83	0.00	0.00	0.00	0.00	0.00	511.75	1,261.51
2017	1.00	22.22	11.10	0.00	0.00	0.00	0.00	0.00	410.68	1,569.13
2018	1.00	17.88	8.93	0.00	0.00	0.00	0.00	0.00	330.58	1,793.29
2019	1.00	14.39	7.19	0.00	0.00	0.00	0.00	0.00	266.10	1,956.64
2020	1.00	11.60	5.80	0.00	0.00	0.00	0.00	0.00	214.73	2,075.96
2021	1.00	9.31	4.66	0.00	0.00	0.00	0.00	0.00	172.32	2,162.62
2022	1.00	7.49	3.75	0.00	0.00	0.00	0.00	0.00	138.72	2,225.78
2023	1.00	6.02	3.02	0.00	0.00	0.00	0.00	0.00	111.66	2,271.81
2024	1.00	4.86	2.44	0.00	0.00	0.00	0.00	0.00	90.11	2,305.42
2025	1.00	3.90	1.95	0.00	0.00	0.00	0.00	0.00	72.32	2,329.84
2026	1.00	3.14	1.57	0.00	0.00	0.00	0.00	0.00	58.21	2,347.64
2027	1.00	2.52	1.27	0.00	0.00	0.00	0.00	0.00	46.86	2,360.61
2028	1.00	2.00	1.00	0.00	0.00	0.00	0.00	0.00	37.16	2,369.93
Rem.		0.17	0.06	0.00	0.00	0.00	0.00	0.00	2.02	0.47
Total		182.11	90.86	0.00	0.00	0.00	0.00	0.00	3,361.58	2,370.39

Major Phase :	Oil			Abandonment Date :	7/1/2029
Perfs :	8741 - 8744			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	390.20	bbl/month		Revenue Int :	0.81045170	PW	5.00% :	2,789.01
Abandonment :	0.00	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	2,370.39
Initial Decline :	19.44	% year	b =0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	2,054.86
Beg Ratio :	6.219			Years to Payout :	0.00	PW	20.00% :	1,810.41
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	1,616.38
						PW	30.00% :	1,459.11

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

12

Date : 08/21/2014 11:45:32 AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date : 07/31/2014	Case	:	ST 02-3A #001 (23530) - GBE
Partner :	All Cases	Discount Rate (%) : 10.00	Reserve Cat.	:	Proved Producing
Case Type :	LEASE CASE	All Cases	Field	:	FISHERS REEF
Archive Set :	RED.07.14		Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT	Reservoir	:	Frio 15
Cum Oil (Mbbl) :	747.42		Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	14.65

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	1.94	71.12	1.41	45.00	109.34	5.79	154.58	260.73	0.00
2015	3.94	144.09	2.86	91.17	109.34	5.79	313.19	528.27	0.00
2016	3.16	115.57	2.30	73.13	109.34	5.79	251.21	423.71	0.00
2017	2.52	92.19	1.83	58.33	109.34	5.79	200.38	337.99	0.00
2018	2.02	73.76	1.47	46.67	109.34	5.79	160.33	270.43	0.00
2019	1.61	59.02	1.17	37.34	109.34	5.79	128.28	216.38	0.00
2020	1.29	47.34	0.94	29.95	109.34	5.79	102.89	173.55	0.00
2021	1.03	37.76	0.75	23.89	109.34	5.79	82.08	138.44	0.00
2022	0.83	30.21	0.60	19.12	109.34	5.79	65.67	110.77	0.00
2023	0.66	24.17	0.48	15.30	109.34	5.79	52.55	88.63	0.00
2024	0.53	19.39	0.39	12.27	109.34	5.79	42.15	71.09	0.00
2025	0.42	15.47	0.31	9.79	109.34	5.79	33.62	56.70	0.00
2026	0.34	12.38	0.25	7.83	109.34	5.79	26.90	45.37	0.00
2027	0.27	9.90	0.20	6.27	109.34	5.79	21.52	36.30	0.00
2028	0.22	7.94	0.16	5.03	109.34	5.79	17.26	29.12	0.00
Rem	0.09	3.34	0.07	2.11	109.34	5.79	7.25	12.23	0.00
Total	20.87	763.65	15.18	483.19	109.34	5.79	1,659.86	2,799.71	0.00
Ult	768.30	778.30

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	26.67	10.38	0.00	0.00	0.00	0.00	0.00	378.26	370.52
2015	1.00	54.03	21.04	0.00	0.00	0.00	0.00	0.00	766.40	1,071.24
2016	1.00	43.33	16.87	0.00	0.00	0.00	0.00	0.00	614.71	1,579.97
2017	1.00	34.57	13.46	0.00	0.00	0.00	0.00	0.00	490.34	1,947.29
2018	1.00	27.66	10.77	0.00	0.00	0.00	0.00	0.00	392.34	2,213.34
2019	1.00	22.13	8.62	0.00	0.00	0.00	0.00	0.00	313.92	2,406.05
2020	1.00	17.75	6.91	0.00	0.00	0.00	0.00	0.00	251.79	2,545.96
2021	1.00	14.16	5.51	0.00	0.00	0.00	0.00	0.00	200.85	2,646.98
2022	1.00	11.33	4.41	0.00	0.00	0.00	0.00	0.00	160.70	2,720.15
2023	1.00	9.06	3.53	0.00	0.00	0.00	0.00	0.00	128.58	2,773.15
2024	1.00	7.27	2.83	0.00	0.00	0.00	0.00	0.00	103.13	2,811.63
2025	1.00	5.80	2.26	0.00	0.00	0.00	0.00	0.00	82.27	2,839.41
2026	1.00	4.64	1.81	0.00	0.00	0.00	0.00	0.00	65.82	2,859.54
2027	1.00	3.71	1.45	0.00	0.00	0.00	0.00	0.00	52.67	2,874.11
2028	1.00	2.98	1.16	0.00	0.00	0.00	0.00	0.00	42.24	2,884.69
Rem.		1.25	0.49	0.00	0.00	0.00	0.00	0.00	17.74	4.12
Total		286.33	111.49	0.00	0.00	0.00	0.00	0.00	4,061.75	2,888.81

Major Phase :	Gas			Abandonment Date :	7/1/2029
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	14,718.59	Mcf/month		Revenue Int :	0.72729100	PW	5.00% :	3,384.05
Abandonment :	527.36	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	2,888.81
Initial Decline :	20.00	% year	b =0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	2,515.31
Beg Ratio :	0.027			Years to Payout :	0.00	PW	20.00% :	2,225.59
End Ratio :	0.027			Internal ROR (%) :	0.00	PW	25.00% :	1,995.29
						PW	30.00% :	1,808.27

RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529

13

Date : 08/21/2014 11:45:32 AM
		ECONOMIC PROJECTION
		As Of Date :	07/31/2014	Case	:	ST 05-8A (230143) #01 - GBE
Project Name :	HYDROCARB ENERGY 06/30/2014	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Producing
Partner :	All Cases	All Cases		Field	:	FISHERS REEF
Case Type :	LEASE CASE			Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :	RED.07.14	SEC REPORT		Reservoir	:	FRIO 17
				Co., State :		CHAMBERS, TX
Cum Oil (Mbbl) :	12.84
Cum Gas (MMcf) :	1,395.84

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.01	7.61	0.00	4.57	109.34	5.79	0.48	26.45	0.00
2015	0.01	13.01	0.01	7.80	109.34	5.79	0.86	45.21	0.00
2016	0.01	8.14	0.01	4.88	109.34	5.79	0.58	28.29	0.00
2017	0.01	5.07	0.00	3.04	109.34	5.79	0.38	17.61	0.00
2018	0.00	2.43	0.00	1.45	109.34	5.79	0.20	8.43	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.03	36.26	0.02	21.74	109.34	5.79	2.49	125.99	0.00
Ult	12.87	1,432.10

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	2.01	0.67	0.00	0.00	0.00	0.00	0.00	24.25	23.76
2015	1.00	3.43	1.15	0.00	0.00	0.00	0.00	0.00	41.48	61.77
2016	1.00	2.15	0.72	0.00	0.00	0.00	0.00	0.00	26.00	83.33
2017	1.00	1.34	0.45	0.00	0.00	0.00	0.00	0.00	16.21	95.49
2018	0.00	0.64	0.22	0.00	0.00	0.00	0.00	0.00	7.77	100.83
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		9.56	3.21	0.00	0.00	0.00	0.00	0.00	115.71	100.83

Major Phase :	Gas			Abandonment Date :	9/20/2018
Perfs :	0 - 0			Working Int :	0.87500000	Present Worth Profile (M$)
Initial Rate :	1,657.16	Mcf/month		Revenue Int :	0.68923710	PW	5.00% :	107.84
Abandonment :	235.76	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	100.83
Initial Decline :	37.57	% year	b=0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	94.56
Beg Ratio :	0.001			Years to Payout :	0.00	PW	20.00% :	88.93
End Ratio :	0.001			Internal ROR (%) :	0.00	PW	25.00% :	83.86
						PW	30.00% :	79.28

RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529

14

Date : 08/21/2014 11:45:32 AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 06-7A #01 ST (25088) - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Producing
Case Type :	LEASE CASE	All Cases		Field	:	FISHERS REEF
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	FRIO 15
Cum Oil (Mbbl) :	98.09			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	175.86

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.74	1.62	0.42	0.79	109.34	5.79	45.78	4.58	0.00
2015	1.35	2.83	0.76	1.39	109.34	5.79	83.09	8.03	0.00
2016	0.17	0.35	0.10	0.17	109.34	5.79	10.69	1.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	2.27	4.80	1.28	2.35	109.34	5.79	139.57	13.60	0.00
Ult	100.36	180.66

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	2.45	1.26	0.00	0.00	0.00	0.00	0.00	46.65	45.71
2015	1.00	4.42	2.28	0.00	0.00	0.00	0.00	0.00	84.42	122.99
2016	1.00	0.57	0.29	0.00	0.00	0.00	0.00	0.00	10.83	132.32
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		7.44	3.83	0.00	0.00	0.00	0.00	0.00	141.90	132.32

Major Phase :	Oil			Abandonment Date :	2/28/2016
Perfs :	0 - 0			Working Int :	0.75000000	Present Worth Profile (M$)
Initial Rate :	159.27	bbl/month		Revenue Int :	0.56206053	PW	5.00% :	136.98
Abandonment :	87.01	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	132.32
Initial Decline :	31.80	% year	b =0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	127.90
Beg Ratio :	2.190			Years to Payout :	0.00	PW	20.00% :	123.70
End Ratio :	2.023			Internal ROR (%) :	0.00	PW	25.00% :	119.72
						PW	30.00% :	115.93

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

15

Date :     08/21/2014 11:45:32AM		ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Producing Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00	POINT BOLIVAR NORTH Field
Case Type :	REPORT BREAK TOTAL CASE	All Cases
SEC REPORT

Cum Oil (Mbbl) :		419.38
Cum Gas (MMcf) :		122.40
	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.03	0.00	0.02	0.00	88.35	0.00	1.60	0.00	0.00
2015	0.05	0.00	0.04	0.00	88.35	0.00	3.23	0.00	0.00
2016	0.02	0.00	0.01	0.00	88.35	0.00	1.15	0.00	0.00

Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.10	0.00	0.07	0.00	88.35	0.00	5.98	0.00	0.00
Ult	419.48	122.40

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.07	0.04	0.00	0.00	0.00	0.00	0.00	1.49	1.46
2015	1.00	0.15	0.08	0.00	0.00	0.00	0.00	0.00	3.00	4.20
2016	1.00	0.05	0.03	0.00	0.00	0.00	0.00	0.00	1.07	5.11

Rem.	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.28	0.15	0.00	0.00	0.00	0.00	0.00	5.56	5.11

		Present Worth Profile (M$)
		PW	5.00% :	5.32
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	5.11
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	4.90
Years to Payout :	0.00	PW	20.00% :	4.71
Internal ROR (%) :	0.00	PW	25.00% :	4.53
		PW	30.00% :	4.36

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

16

Date : 08/21/2014 11:45:32 AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 343 18 (18424) A-1a Thru A-1d -
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Producing
Case Type :	LEASE CASE	All Cases		Field	:	POINT BOLIVAR NORTH
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	S-2 B2
				Co., State	:	GALVESTON, TX

Cum Oil (Mbbl) :	419.38
Cum Gas (MMcf) :	122.40

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.03	0.00	0.02	0.00	88.35	0.00	1.60	0.00	0.00
2015	0.05	0.00	0.04	0.00	88.35	0.00	3.23	0.00	0.00
2016	0.02	0.00	0.01	0.00	88.35	0.00	1.15	0.00	0.00

Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.10	0.00	0.07	0.00	88.35	0.00	5.98	0.00	0.00
Ult	419.48	122.40

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.07	0.04	0.00	0.00	0.00	0.00	0.00	1.49	1.46
2015	1.00	0.15	0.08	0.00	0.00	0.00	0.00	0.00	3.00	4.20
2016	1.00	0.05	0.03	0.00	0.00	0.00	0.00	0.00	1.07	5.11

Rem.	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.28	0.15	325.00	0.00	0.00	0.00	0.00	5.56	5.11

Major Phase :	Oil			Abandonment Date :	6/1/2016
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	5.42	bbl/month		Revenue Int :	0.69375100	PW	5.00	% :	5.32
Abandonment :	3.55	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00	% :	5.11
Initial Decline :	20.64	% year	b=0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00	% :	4.90
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00	% :	4.71
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00	% :	4.53
						PW	30.00	% :	4.36

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

17

Date :     08/21/2014 11:45:32AM
ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Producing Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00	RED FISH REEF Field
Case Type :	REPORT BREAK TOTAL CASE	All Cases
		SEC REPORT

Cum Oil (Mbbl) :	666.50
Cum Gas (MMcf) :	27,144.55

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	4.67	46.10	3.87	34.62	109.29	4.00	423.12	138.47	0.00
2015	9.05	91.83	7.49	68.91	109.29	4.00	818.32	275.65	0.00
2016	6.95	72.44	5.75	54.32	109.29	4.00	628.24	217.30	0.00
2017	5.45	57.41	4.51	43.02	109.29	4.00	492.54	172.09	0.00
2018	4.39	46.09	3.63	34.52	109.29	4.00	396.32	138.06	0.00
2019	3.61	37.37	2.98	27.96	109.29	4.00	325.20	111.85	0.00
2020	2.98	30.50	2.46	22.80	109.29	4.00	269.00	91.21	0.00
2021	2.51	25.09	2.07	18.75	109.29	4.00	226.59	74.98	0.00
2022	2.16	20.96	1.78	15.65	109.29	4.00	194.83	62.59	0.00
2023	1.87	16.16	1.54	12.03	109.29	4.00	168.79	48.12	0.00
2024	1.60	11.94	1.32	8.86	109.29	4.00	144.63	35.45	0.00
2025	1.36	10.26	1.12	7.61	109.29	4.00	122.17	30.45	0.00
2026	1.21	9.12	1.00	6.76	109.29	4.00	109.20	27.05	0.00
2027	1.04	7.94	0.86	5.89	109.29	4.00	94.11	23.56	0.00
2028	0.72	6.14	0.59	4.56	109.29	4.00	64.72	18.23	0.00
Rem	1.24	10.27	1.02	7.62	109.29	4.00	111.71	30.46	0.00
Total	50.83	499.64	41.99	373.88	109.29	4.00	4,589.48	1,495.52	0.00
Ult	717.33	27,644.19

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	6.00	29.85	14.04	0.00	0.00	0.00	26.90	0.00	490.81	480.80
2015	6.00	58.32	27.35	0.00	0.00	0.00	54.28	0.00	954.01	1,353.44
2016	6.00	45.20	21.14	0.00	0.00	0.00	44.01	0.00	735.19	1,962.01
2017	6.00	35.56	16.62	0.00	0.00	0.00	36.14	0.00	576.30	2,393.74
2018	6.00	28.59	13.36	0.00	0.00	0.00	30.24	0.00	462.20	2,707.14
2019	6.00	23.35	10.93	0.00	0.00	0.00	25.66	0.00	377.12	2,938.60
2020	5.00	19.22	9.01	0.00	0.00	0.00	21.94	0.00	310.05	3,110.86
2021	5.00	16.05	7.54	0.00	0.00	0.00	18.97	0.00	259.02	3,241.07
2022	5.00	13.66	6.44	0.00	0.00	0.00	16.65	0.00	220.68	3,341.50
2023	4.00	11.37	5.42	0.00	0.00	0.00	14.15	0.00	185.96	3,418.14
2024	2.00	9.31	4.50	0.00	0.00	0.00	11.95	0.00	154.31	3,475.71
2025	2.00	7.90	3.82	0.00	0.00	0.00	10.72	0.00	130.18	3,519.63
2026	2.00	7.05	3.41	0.00	0.00	0.00	9.79	0.00	116.01	3,555.06
2027	1.00	6.10	2.94	0.00	0.00	0.00	8.86	0.00	99.78	3,582.70
2028	1.00	4.34	2.07	0.00	0.00	0.00	7.63	0.00	68.90	3,599.94
Rem.		7.42	3.55	0.00	0.00	0.00	13.05	0.00	118.14	25.63
Total		323.28	152.13	0.00	0.00	0.00	350.96	0.00	5,258.64	3,625.57

		Present Worth Profile (M$)
		PW	5.00% :	4,298.86
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	3,625.57
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	3,133.76
Years to Payout :	0.00	PW	20.00% :	2,761.43
Internal ROR (%) :	0.00	PW	25.00% :	2,470.72
		PW	30.00% :	2,237.70

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

18

Date :      08/21/2014  11:45:32AM
ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	RFRU 224 185 (099996) - GBE (0999
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Producing
Case Type :	LEASE CASE	All Cases		Field	:	RED FISH REEF
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	FB A-1 FRIO 22C
Cum Oil (Mbbl) :	23.94			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	3,247.25

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.06	0.16	0.05	0.12	109.29	4.00	5.40	0.49	0.00
2015	0.12	0.35	0.11	0.26	109.29	4.00	11.51	1.06	0.00
2016	0.11	0.31	0.09	0.23	109.29	4.00	9.92	0.93	0.00
2017	0.09	0.27	0.08	0.20	109.29	4.00	8.50	0.82	0.00
2018	0.08	0.24	0.07	0.18	109.29	4.00	7.31	0.72	0.00
2019	0.07	0.21	0.06	0.16	109.29	4.00	6.28	0.63	0.00
2020	0.06	0.18	0.05	0.14	109.29	4.00	5.41	0.55	0.00
2021	0.05	0.16	0.04	0.12	109.29	4.00	4.64	0.49	0.00
2022	0.04	0.14	0.04	0.11	109.29	4.00	3.99	0.43	0.00
2023	0.04	0.12	0.03	0.09	109.29	4.00	3.43	0.38	0.00
2024	0.03	0.10	0.03	0.08	109.29	4.00	2.81	0.31	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.75	2.23	0.63	1.70	109.29	4.00	69.20	6.80	0.00
Ult	24.69	3,249.49

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.29	0.15	0.00	0.00	0.00	0.07	0.00	5.39	5.27
2015	1.00	0.61	0.31	0.00	0.00	0.00	0.16	0.00	11.48	15.77
2016	1.00	0.53	0.27	0.00	0.00	0.00	0.14	0.00	9.91	23.97
2017	1.00	0.45	0.23	0.00	0.00	0.00	0.12	0.00	8.51	30.34
2018	1.00	0.39	0.20	0.00	0.00	0.00	0.11	0.00	7.33	35.30
2019	1.00	0.34	0.17	0.00	0.00	0.00	0.09	0.00	6.31	39.17
2020	1.00	0.29	0.15	0.00	0.00	0.00	0.08	0.00	5.45	42.20
2021	1.00	0.25	0.13	0.00	0.00	0.00	0.07	0.00	4.68	44.55
2022	1.00	0.22	0.11	0.00	0.00	0.00	0.06	0.00	4.03	46.38
2023	1.00	0.19	0.10	0.00	0.00	0.00	0.06	0.00	3.47	47.81
2024	0.00	0.15	0.08	0.00	0.00	0.00	0.05	0.00	2.85	48.88
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		3.69	1.90	0.00	0.00	0.00	1.00	0.00	69.40	48.88

Major Phase :	Gas			Abandonment Date :	12/12/2024
Perfs :	10878 - 11062			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	32.60	Mcf/month		Revenue Int :	0.84500000	PW	5.00% :	57.69
Abandonment :	8.53	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	48.88
Initial Decline :	12.13	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	42.11
Beg Ratio :	0.366			Years to Payout :	0.00	PW	20.00% :	36.83
End Ratio :	0.291			Internal ROR (%) :	0.00	PW	25.00% :	32.64
						PW	30.00% :	29.25

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

19

Date :      08/21/2014 11:45:32AM
ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 224 141U (052698) - GBE (05269
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Producing
Case Type :	LEASE CASE	All Cases		Field	:	RED FISH REEF
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	FB A-2 FRIO 19
Cum Oil (Mbbl) :	173.14			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	12,617.21

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.17	19.96	0.14	15.18	109.29	4.00	15.53	60.71	0.00
2015	0.28	38.66	0.24	29.40	109.29	4.00	25.83	117.61	0.00
2016	0.17	29.07	0.14	22.11	109.29	4.00	15.54	88.44	0.00
2017	0.10	21.74	0.09	16.53	109.29	4.00	9.29	66.13	0.00
2018	0.06	16.31	0.05	12.40	109.29	4.00	5.58	49.61	0.00
2019	0.04	12.23	0.03	9.30	109.29	4.00	3.35	37.21	0.00
2020	0.02	9.20	0.02	7.00	109.29	4.00	2.01	27.98	0.00
2021	0.01	6.88	0.01	5.23	109.29	4.00	1.20	20.92	0.00
2022	0.01	5.16	0.01	3.92	109.29	4.00	0.72	15.70	0.00
2023	0.00	2.37	0.00	1.80	109.29	4.00	0.28	7.22	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.86	161.58	0.73	122.88	109.29	4.00	79.33	491.53	0.00
Ult	174.00	12,778.79

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	5.27	1.91	0.00	0.00	0.00	7.54	0.00	61.52	60.27
2015	1.00	10.01	3.59	0.00	0.00	0.00	14.60	0.00	115.25	165.74
2016	1.00	7.35	2.60	0.00	0.00	0.00	10.98	0.00	83.05	234.53
2017	1.00	5.39	1.89	0.00	0.00	0.00	8.21	0.00	59.94	279.47
2018	1.00	3.98	1.38	0.00	0.00	0.00	6.16	0.00	43.67	309.10
2019	1.00	2.95	1.01	0.00	0.00	0.00	4.62	0.00	31.98	328.75
2020	1.00	2.19	0.75	0.00	0.00	0.00	3.47	0.00	23.58	341.86
2021	1.00	1.62	0.55	0.00	0.00	0.00	2.60	0.00	17.35	350.60
2022	1.00	1.21	0.41	0.00	0.00	0.00	1.95	0.00	12.85	356.45
2023	0.00	0.55	0.19	0.00	0.00	0.00	0.90	0.00	5.86	358.91
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		40.51	14.27	0.00	0.00	0.00	61.02	0.00	455.05	358.91

Major Phase :	Gas		Abandonment Date :	7/30/2023
Perfs :	0 - 0		Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	4,184.88	Mcf/month	Revenue Int :	0.84500000	PW	5.00% :	401.90
Abandonment :	314.53	Mcf/month	Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	358.91
Initial Decline :	25.00% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	323.68
Beg Ratio :	0.009		Years to Payout :	0.00	PW	20.00% :	294.45
End Ratio :	0.001		Internal ROR (%) :	0.00	PW	25.00% :	269.90
					PW	30.00% :	249.05

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

20

Date :      08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case :	ST 225 139 (23981) - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat. :	Proved Producing
Case Type :	LEASE CASE	All Cases		Field :	RED FISH REEF
Archive Set :	RED.07.14			Operator :	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir :	FRIO 15
Cum Oil (Mbbl) :	60.64			Co., State :	CHAMBERS, TX
Cum Gas (MMcf) :	357.30

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.75	2.19	0.64	1.67	109.29	4.00	69.56	6.67	0.00
2015	1.17	3.65	0.99	2.77	109.29	4.00	108.31	11.09	0.00
2016	0.64	2.19	0.54	1.67	109.29	4.00	59.04	6.67	0.00
2017	0.35	1.31	0.29	1.00	109.29	4.00	32.00	3.99	0.00
2018	0.19	0.79	0.16	0.60	109.29	4.00	17.41	2.39	0.00
2019	0.10	0.47	0.09	0.36	109.29	4.00	9.47	1.44	0.00
2020	0.02	0.12	0.02	0.09	109.29	4.00	2.20	0.36	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	3.23	10.72	2.73	8.15	109.29	4.00	298.00	32.61	0.00
Ult	63.87	368.02

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	3.70	1.91	0.00	0.00	0.00	2.69	0.00	67.93	66.58
2015	1.00	5.81	2.99	0.00	0.00	0.00	4.28	0.00	106.32	164.09
2016	1.00	3.22	1.64	0.00	0.00	0.00	2.41	0.00	58.44	212.60
2017	1.00	1.77	0.90	0.00	0.00	0.00	1.35	0.00	31.97	236.62
2018	1.00	0.98	0.50	0.00	0.00	0.00	0.76	0.00	17.56	248.57
2019	1.00	0.54	0.27	0.00	0.00	0.00	0.43	0.00	9.66	254.52
2020	0.00	0.13	0.06	0.00	0.00	0.00	0.10	0.00	2.27	255.82
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		16.15	8.27	0.00	0.00	0.00	12.03	0.00	294.15	255.82

Major Phase :	Oil			Abandonment Date :	5/9/2020
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :		168.54	bbl/month	Revenue Int :	0.84500000	PW	5.00% :	273.75
Abandonment :		5.00	bbl/month	Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	255.82
Initial Decline :		45.62	% year        b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	239.97
Beg Ratio :		2.853		Years to Payout :	0.00	PW	20.00% :	225.89
End Ratio :		5.036		Internal ROR (%) :	0.00	PW	25.00% :	213.33
						PW	30.00% :	202.06

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

21

Date :        08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date : 07/31/2014	Case :	ST 246 120 (06840) - GBE
Partner :	All Cases	Discount Rate (%) : 10.00	Reserve Cat. :	Proved Producing
Case Type :	LEASE CASE	All Cases	Field :	RED FISH REEF
Archive Set :	RED.07.14		Operator :	GALVESTON BAY ENERGY LLC
		SEC REPORT	Reservoir :	FRIO 25-A
Cum Oil (Mbbl) :	307.83		Co., State :	CHAMBERS, TX
Cum Gas (MMcf) :	2,239.21

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.80	9.28	0.66	6.88	109.29	4.00	71.81	27.52	0.00
2015	1.80	20.58	1.48	15.27	109.29	4.00	161.87	61.07	0.00
2016	1.68	18.80	1.38	13.95	109.29	4.00	151.23	55.78	0.00
2017	1.56	17.08	1.29	12.67	109.29	4.00	140.51	50.68	0.00
2018	1.45	15.56	1.20	11.54	109.29	4.00	130.92	46.17	0.00
2019	1.35	14.18	1.12	10.52	109.29	4.00	121.99	42.07	0.00
2020	1.27	12.95	1.04	9.61	109.29	4.00	113.97	38.42	0.00
2021	1.18	11.77	0.97	8.73	109.29	4.00	105.89	34.91	0.00
2022	1.10	10.72	0.90	7.95	109.29	4.00	98.66	31.80	0.00
2023	1.02	9.77	0.84	7.24	109.29	4.00	91.93	28.97	0.00
2024	0.95	8.92	0.79	6.62	109.29	4.00	85.88	26.47	0.00
2025	0.89	8.10	0.73	6.01	109.29	4.00	79.80	24.04	0.00
2026	0.83	7.38	0.68	5.48	109.29	4.00	74.35	21.91	0.00
2027	0.77	6.73	0.63	4.99	109.29	4.00	69.28	19.96	0.00
2028	0.72	6.14	0.59	4.56	109.29	4.00	64.72	18.23	0.00
Rem	1.24	10.27	1.02	7.62	109.29	4.00	111.71	30.46	0.00
Total	18.59	188.23	15.32	139.62	109.29	4.00	1,674.52	558.47	0.00
Ult	326.42	2,427.44

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	5.37	2.48	0.00	0.00	0.00	9.37	0.00	82.11	80.41
2015	1.00	12.03	5.57	0.00	0.00	0.00	21.00	0.00	184.34	248.75
2016	1.00	11.14	5.18	0.00	0.00	0.00	19.46	0.00	171.23	390.29
2017	1.00	10.26	4.78	0.00	0.00	0.00	17.94	0.00	158.20	508.66
2018	1.00	9.49	4.43	0.00	0.00	0.00	16.59	0.00	146.59	607.95
2019	1.00	8.77	4.10	0.00	0.00	0.00	15.34	0.00	135.85	691.25
2020	1.00	8.12	3.81	0.00	0.00	0.00	14.22	0.00	126.23	761.30
2021	1.00	7.49	3.52	0.00	0.00	0.00	13.12	0.00	116.67	819.91
2022	1.00	6.92	3.26	0.00	0.00	0.00	12.13	0.00	108.15	869.10
2023	1.00	6.40	3.02	0.00	0.00	0.00	11.22	0.00	100.26	910.37
2024	1.00	5.94	2.81	0.00	0.00	0.00	10.41	0.00	93.20	945.10
2025	1.00	5.47	2.60	0.00	0.00	0.00	9.61	0.00	86.17	974.16
2026	1.00	5.06	2.41	0.00	0.00	0.00	8.89	0.00	79.90	998.56
2027	1.00	4.68	2.23	0.00	0.00	0.00	8.23	0.00	74.10	1,019.04
2028	1.00	4.34	2.07	0.00	0.00	0.00	7.63	0.00	68.90	1,036.28
Rem.		7.42	3.55	0.00	0.00	0.00	13.05	0.00	118.14	25.63
Total		118.91	55.82	0.00	0.00	0.00	208.21	0.00	1,850.03	1,061.91

Major Phase :	Oil			Abandonment Date :	12/1/2030
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :		159.89	bbl/month	Revenue Int :	0.82416700	PW	5.00% :	1,369.55
Abandonment :		50.35	bbl/month	Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	1,061.91
Initial Decline :		6.83	% year        b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	856.04
Beg Ratio :		11.690		Years to Payout :	0.00	PW	20.00% :	712.33
End Ratio :		8.098		Internal ROR (%) :	0.00	PW	25.00% :	608.04
						PW	30.00% :	529.69

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

22

Date :       08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date : 07/31/2014	Case :	ST 246 183 (096910) - GBE
Partner :	All Cases	Discount Rate (%) : 10.00	Reserve Cat. :	Proved Producing
Case Type :	LEASE CASE	All Cases	Field :	RED FISH REEF
Archive Set :	RED.07.14		Operator :	GALVESTON BAY ENERGY LLC
		SEC REPORT	Reservoir :	FRIO 2-A
Cum Oil (Mbbl) :	50.30		Co., State :	CHAMBERS, TX
Cum Gas (MMcf) :	4,310.98

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	1.28	5.14	1.06	3.81	109.29	4.00	115.39	15.26	0.00
2015	2.34	9.51	1.93	7.06	109.29	4.00	210.47	28.23	0.00
2016	1.61	6.69	1.33	4.96	109.29	4.00	144.95	19.85	0.00
2017	1.10	4.68	0.91	3.47	109.29	4.00	99.28	13.88	0.00
2018	0.76	3.28	0.62	2.44	109.29	4.00	68.22	9.74	0.00
2019	0.52	2.30	0.43	1.71	109.29	4.00	46.88	6.84	0.00
2020	0.36	1.62	0.30	1.20	109.29	4.00	32.29	4.81	0.00
2021	0.25	1.13	0.20	0.84	109.29	4.00	22.11	3.36	0.00
2022	0.17	0.80	0.14	0.59	109.29	4.00	15.20	2.36	0.00
2023	0.12	0.56	0.10	0.41	109.29	4.00	10.44	1.66	0.00
2024	0.05	0.23	0.04	0.17	109.29	4.00	4.24	0.68	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	8.54	35.95	7.04	26.67	109.29	4.00	769.48	106.67	0.00
Ult	58.84	4,346.93

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	6.45	3.27	0.00	0.00	0.00	2.36	0.00	118.57	116.17
2015	1.00	11.80	5.97	0.00	0.00	0.00	4.35	0.00	216.58	314.43
2016	1.00	8.16	4.12	0.00	0.00	0.00	3.05	0.00	149.48	438.29
2017	1.00	5.61	2.83	0.00	0.00	0.00	2.12	0.00	102.60	515.25
2018	1.00	3.87	1.95	0.00	0.00	0.00	1.48	0.00	70.66	563.23
2019	1.00	2.67	1.34	0.00	0.00	0.00	1.04	0.00	48.67	593.14
2020	1.00	1.85	0.93	0.00	0.00	0.00	0.73	0.00	33.59	611.83
2021	1.00	1.27	0.64	0.00	0.00	0.00	0.51	0.00	23.06	623.44
2022	1.00	0.88	0.44	0.00	0.00	0.00	0.35	0.00	15.89	630.68
2023	1.00	0.60	0.30	0.00	0.00	0.00	0.25	0.00	10.94	635.20
2024	0.00	0.25	0.12	0.00	0.00	0.00	0.10	0.00	4.45	636.90
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		43.40	21.90	0.00	0.00	0.00	16.34	0.00	794.50	636.90

Major Phase :	Oil			Abandonment Date :	7/17/2024
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :		273.49	bbl/month	Revenue Int :	0.82416700	PW	5.00% :	707.60
Abandonment :		6.49	bbl/month	Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	636.90
Initial Decline :		31.30	% year        b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	578.56
Beg Ratio :		3.997		Years to Payout :	0.00	PW	20.00% :	529.78
End Ratio :		4.922		Internal ROR (%) :	0.00	PW	25.00% :	488.49
						PW	30.00% :	453.17

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

23

Date :       08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case :	ST 247 188 (102549) - GBE (102549)
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat. :	Proved Producing
Case Type :	LEASE CASE	All Cases		Field :	RED FISH REEF
Archive Set :	RED.07.14			Operator :	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir :	AB-4
Cum Oil (Mbbl) :	50.65			Co., State :	CHAMBERS, TX
Cum Gas (MMcf) :	4,372.60

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	1.61	9.38	1.33	6.96	109.29	4.00	145.43	27.83	0.00
2015	3.33	19.07	2.75	14.15	109.29	4.00	300.32	56.59	0.00
2016	2.75	15.38	2.27	11.41	109.29	4.00	247.56	45.63	0.00
2017	2.25	12.33	1.86	9.15	109.29	4.00	202.96	36.59	0.00
2018	1.85	9.92	1.53	7.36	109.29	4.00	166.89	29.43	0.00
2019	1.52	7.98	1.26	5.92	109.29	4.00	137.23	23.67	0.00
2020	1.26	6.43	1.04	4.77	109.29	4.00	113.12	19.08	0.00
2021	1.03	5.16	0.85	3.83	109.29	4.00	92.74	15.30	0.00
2022	0.85	4.15	0.70	3.08	109.29	4.00	76.26	12.31	0.00
2023	0.70	3.34	0.57	2.48	109.29	4.00	62.71	9.90	0.00
2024	0.57	2.69	0.47	2.00	109.29	4.00	51.69	7.98	0.00
2025	0.47	2.16	0.39	1.60	109.29	4.00	42.38	6.40	0.00
2026	0.39	1.74	0.32	1.29	109.29	4.00	34.85	5.15	0.00
2027	0.28	1.21	0.23	0.90	109.29	4.00	24.83	3.60	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	18.86	100.93	15.55	74.86	109.29	4.00	1,698.96	299.45	0.00
Ult	69.52	4,473.53

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	8.78	4.33	0.00	0.00	0.00	4.86	0.00	155.29	152.10
2015	1.00	18.06	8.92	0.00	0.00	0.00	9.89	0.00	320.03	444.65
2016	1.00	14.81	7.33	0.00	0.00	0.00	7.98	0.00	263.07	662.32
2017	1.00	12.08	5.99	0.00	0.00	0.00	6.40	0.00	215.08	823.40
2018	1.00	9.88	4.91	0.00	0.00	0.00	5.14	0.00	176.38	942.99
2019	1.00	8.09	4.02	0.00	0.00	0.00	4.14	0.00	144.65	1,031.77
2020	1.00	6.63	3.31	0.00	0.00	0.00	3.34	0.00	118.93	1,097.84
2021	1.00	5.41	2.70	0.00	0.00	0.00	2.68	0.00	97.25	1,146.75
2022	1.00	4.43	2.21	0.00	0.00	0.00	2.15	0.00	79.77	1,183.06
2023	1.00	3.63	1.82	0.00	0.00	0.00	1.73	0.00	65.43	1,210.03
2024	1.00	2.98	1.49	0.00	0.00	0.00	1.40	0.00	53.81	1,230.10
2025	1.00	2.43	1.22	0.00	0.00	0.00	1.12	0.00	44.01	1,244.96
2026	1.00	1.99	1.00	0.00	0.00	0.00	0.90	0.00	36.11	1,256.00
2027	0.00	1.41	0.71	0.00	0.00	0.00	0.63	0.00	25.68	1,263.15
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		100.61	49.96	0.00	0.00	0.00	52.35	0.00	1,795.50	1,263.15

Major Phase :	Gas			Abandonment Date :	11/8/2027
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :		1,938.98	Mcf/month	Revenue Int :	0.82416670	PW	5.00% :	1,488.37
Abandonment :		107.48	Mcf/month	Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	1,263.15
Initial Decline :		19.58	% year         b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	1,093.40
Beg Ratio :		0.171		Years to Payout :	0.00	PW	20.00% :	962.15
End Ratio :		0.230		Internal ROR (%) :	0.00	PW	25.00% :	858.33
						PW	30.00% :	774.49

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

24

Date :       08/21/2014 11:45:32AM
		ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Producing Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00	TRINITY BAY Field
Case Type :	REPORT BREAK TOTAL CASE	All Cases
		SEC REPORT

Cum Oil (Mbbl) :		702.24
Cum Gas (MMcf) :		1,212.28
	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	10.63	45.16	8.64	0.00	109.28	0.00	944.13	0.00	0.00
2015	24.83	121.32	20.17	0.00	109.28	0.00	2,204.21	0.00	0.00
2016	20.97	106.96	17.04	0.00	109.28	0.00	1,861.69	0.00	0.00
2017	18.11	93.85	14.71	0.00	109.28	0.00	1,607.69	0.00	0.00
2018	16.15	82.64	13.12	0.00	109.28	0.00	1,433.59	0.00	0.00
2019	14.45	72.82	11.74	0.00	109.28	0.00	1,283.35	0.00	0.00
2020	12.99	64.38	10.55	0.00	109.28	0.00	1,153.30	0.00	0.00
2021	11.62	56.65	9.44	0.00	109.28	0.00	1,032.07	0.00	0.00
2022	10.45	50.02	8.49	0.00	109.28	0.00	927.38	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	140.20	693.79	113.90	0.00	109.28	0.00	12,447.41	0.00	0.00
Ult	842.44	1,906.07

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	4.00	43.43	23.60	0.00	0.00	0.00	0.00	0.00	877.10	857.56
2015	4.00	101.39	55.11	0.00	0.00	0.00	0.00	0.00	2,047.71	2,729.48
2016	4.00	85.64	46.54	0.00	0.00	0.00	0.00	0.00	1,729.51	4,159.90
2017	3.00	73.95	40.19	0.00	0.00	0.00	0.00	0.00	1,493.54	5,277.82
2018	3.00	65.95	35.84	0.00	0.00	0.00	0.00	0.00	1,331.81	6,180.13
2019	3.00	59.03	32.08	0.00	0.00	0.00	0.00	0.00	1,192.23	6,911.36
2020	3.00	53.05	28.83	0.00	0.00	0.00	0.00	0.00	1,071.42	7,506.15
2021	3.00	47.48	25.80	0.00	0.00	0.00	0.00	0.00	958.79	7,987.93
2022	3.00	42.66	23.18	0.00	0.00	0.00	0.00	0.00	861.53	8,379.83
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		572.58	311.19	0.00	0.00	0.00	0.00	0.00	11,563.64	8,379.83

		Present Worth Profile (M$)
		PW	5.00% :	9,774.88
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	8,379.83
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	7,278.27
Years to Payout :	0.00	PW	20.00% :	6,397.64
Internal ROR (%) :	0.00	PW	25.00% :	5,684.98
		PW	30.00% :	5,101.35

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

25

Date : 08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	TBSU #1 (08444) #37 - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Behind Pipe
Case Type :	LEASE CASE	All Cases		Field	:	TRINITY BAY
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	Frio 12
Cum Oil (Mbbl) :	7.83			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	0.46

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	1.94	0.00	1.57	0.00	109.28	0.00	172.12	0.00	0.00
2015	2.13	0.00	1.73	0.00	109.28	0.00	189.28	0.00	0.00
2016	0.68	0.00	0.55	0.00	109.28	0.00	60.49	0.00	0.00
2017	0.05	0.00	0.04	0.00	109.28	0.00	4.16	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	4.80	0.00	3.90	0.00	109.28	0.00	426.05	0.00	0.00
Ult	12.63	0.46

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	7.92	4.30	0.00	0.00	0.00	0.00	0.00	159.90	156.82
2015	1.00	8.71	4.73	0.00	0.00	0.00	0.00	0.00	175.84	318.78
2016	1.00	2.78	1.51	0.00	0.00	0.00	0.00	0.00	56.20	365.63
2017	0.00	0.19	0.10	0.00	0.00	0.00	0.00	0.00	3.87	368.65
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		19.60	10.65	0.00	0.00	0.00	0.00	0.00	395.80	368.65

Major Phase :	Oil			Abandonment Date :	2/20/2017
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	481.36	bbl/month		Revenue Int :	0.81243864	PW	5.00% :	381.79
Abandonment :	25.81	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	368.65
Initial Decline :	68.11	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	356.33
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	344.75
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	333.86

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

26

Date : 08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	TBSU #1 013 (16366) - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Producing
Case Type :	LEASE CASE	All Cases		Field	:	TRINITY BAY
Archive Set :	RED0813			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:
Cum Oil (Mbbl) :	281.43			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	269.59

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	1.93	11.49	1.57	0.00	109.28	0.00	171.19	0.00	0.00
2015	5.87	33.16	4.77	0.00	109.28	0.00	521.03	0.00	0.00
2016	5.35	29.81	4.35	0.00	109.28	0.00	475.41	0.00	0.00
2017	4.86	26.65	3.95	0.00	109.28	0.00	431.41	0.00	0.00
2018	4.42	23.89	3.59	0.00	109.28	0.00	392.61	0.00	0.00
2019	4.02	21.42	3.27	0.00	109.28	0.00	357.30	0.00	0.00
2020	3.67	19.25	2.98	0.00	109.28	0.00	326.01	0.00	0.00
2021	3.33	17.21	2.71	0.00	109.28	0.00	295.84	0.00	0.00
2022	3.03	15.43	2.46	0.00	109.28	0.00	269.23	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	36.49	198.29	29.65	0.00	109.28	0.00	3,240.04	0.00	0.00
Ult	317.92	467.88

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	7.87	4.28	0.00	0.00	0.00	0.00	0.00	159.04	155.04
2015	1.00	23.97	13.03	0.00	0.00	0.00	0.00	0.00	484.04	597.14
2016	1.00	21.87	11.89	0.00	0.00	0.00	0.00	0.00	441.66	962.26
2017	1.00	19.84	10.79	0.00	0.00	0.00	0.00	0.00	400.78	1,262.16
2018	1.00	18.06	9.82	0.00	0.00	0.00	0.00	0.00	364.73	1,509.24
2019	1.00	16.44	8.93	0.00	0.00	0.00	0.00	0.00	331.93	1,712.80
2020	1.00	15.00	8.15	0.00	0.00	0.00	0.00	0.00	302.86	1,880.91
2021	1.00	13.61	7.40	0.00	0.00	0.00	0.00	0.00	274.84	2,019.00
2022	1.00	12.38	6.73	0.00	0.00	0.00	0.00	0.00	250.12	2,132.76
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		149.04	81.00	0.00	0.00	0.00	0.00	0.00	3,010.00	2,132.76

Major Phase :		Oil			Abandonment Date :	1/1/2023
Perfs :		0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	183.53		bbl/month		Revenue Int :	0.81243864	PW	5.00% :	2,516.01
Abandonment :		241.09	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	2,132.76
Initial Decline :		9.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	1,831.80
Beg Ratio :		7.018			Years to Payout :	0.00	PW	20.00% :	1,592.59
End Ratio :		5.048			Internal ROR (%) :	0.00	PW	25.00% :	1,400.16
							PW	30.00% :	1,243.53

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

27

Date : 08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	TBSU #1 12, 35, 130 (8004) - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Producing
Case Type :	LEASE CASE	All Cases		Field	:	TRINITY BAY
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	Frio 12
Cum Oil (Mbbl) :	207.39			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	681.87

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	3.30	19.12	2.68	0.00	109.28	0.00	292.70	0.00	0.00
2015	9.05	56.01	7.35	0.00	109.28	0.00	803.36	0.00	0.00
2016	7.73	47.98	6.28	0.00	109.28	0.00	686.04	0.00	0.00
2017	6.56	40.87	5.33	0.00	109.28	0.00	582.66	0.00	0.00
2018	5.59	34.92	4.54	0.00	109.28	0.00	496.32	0.00	0.00
2019	4.76	29.84	3.87	0.00	109.28	0.00	422.78	0.00	0.00
2020	4.07	25.56	3.30	0.00	109.28	0.00	361.04	0.00	0.00
2021	3.45	21.77	2.81	0.00	109.28	0.00	306.63	0.00	0.00
2022	2.94	18.60	2.39	0.00	109.28	0.00	261.20	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	47.45	294.69	38.55	0.00	109.28	0.00	4,212.72	0.00	0.00
Ult	254.84	976.56

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	13.46	7.32	0.00	0.00	0.00	0.00	0.00	271.91	265.36
2015	1.00	36.95	20.08	0.00	0.00	0.00	0.00	0.00	746.32	947.38
2016	1.00	31.56	17.15	0.00	0.00	0.00	0.00	0.00	637.34	1,474.56
2017	1.00	26.80	14.57	0.00	0.00	0.00	0.00	0.00	541.29	1,879.82
2018	1.00	22.83	12.41	0.00	0.00	0.00	0.00	0.00	461.08	2,192.34
2019	1.00	19.45	10.57	0.00	0.00	0.00	0.00	0.00	392.76	2,433.33
2020	1.00	16.61	9.03	0.00	0.00	0.00	0.00	0.00	335.41	2,619.61
2021	1.00	14.11	7.67	0.00	0.00	0.00	0.00	0.00	284.86	2,762.81
2022	1.00	12.01	6.53	0.00	0.00	0.00	0.00	0.00	242.65	2,873.24
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		193.79	105.32	0.00	0.00	0.00	0.00	0.00	3,913.62	2,873.24

Major Phase :	Oil			Abandonment Date :	1/1/2023
Perfs :	8058 - 8355			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	394.52	bbl/month		Revenue Int :	0.81243864	PW	5.00% :	3,331.56
Abandonment :	226.08	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	2,873.24
Initial Decline :	15.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	2,507.89
Beg Ratio :	4.625			Years to Payout :	0.00	PW	20.00% :	2,213.13
End Ratio :	6.334			Internal ROR (%) :	0.00	PW	25.00% :	1,972.50
						PW	30.00% :	1,773.79

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

28

Date : 08/21/2014 11:45:32AM
		ECONOMIC PROJECTION		Case	:	TBSU #1 69D, 75F, 135 (5351 - GBE
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Reserve Cat.	:	Proved Producing
Partner :	All Cases	Discount Rate (%) :	10.00	Field	:	TRINITY BAY
Case Type :	LEASE CASE	All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :	RED14			Reservoir	:
		SEC REPORT		Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :	205.59
Cum Gas (MMcf) :	260.35

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	3.47	14.55	2.82	0.00	109.28	0.00	308.13	0.00	0.00
2015	7.78	32.14	6.32	0.00	109.28	0.00	690.54	0.00	0.00
2016	7.21	29.17	5.85	0.00	109.28	0.00	639.75	0.00	0.00
2017	6.64	26.33	5.39	0.00	109.28	0.00	589.45	0.00	0.00
2018	6.13	23.83	4.98	0.00	109.28	0.00	544.66	0.00	0.00
2019	5.67	21.57	4.61	0.00	109.28	0.00	503.27	0.00	0.00
2020	5.25	19.57	4.27	0.00	109.28	0.00	466.25	0.00	0.00
2021	4.84	17.67	3.93	0.00	109.28	0.00	429.60	0.00	0.00
2022	4.47	15.99	3.63	0.00	109.28	0.00	396.95	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	51.46	200.81	41.81	0.00	109.28	0.00	4,568.60	0.00	0.00
Ult	257.05	461.16

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	14.17	7.70	0.00	0.00	0.00	0.00	0.00	286.25	280.33
2015	1.00	31.77	17.26	0.00	0.00	0.00	0.00	0.00	641.52	866.18
2016	1.00	29.43	15.99	0.00	0.00	0.00	0.00	0.00	594.33	1,357.46
2017	1.00	27.11	14.74	0.00	0.00	0.00	0.00	0.00	547.60	1,767.18
2018	1.00	25.05	13.62	0.00	0.00	0.00	0.00	0.00	505.99	2,109.90
2019	1.00	23.15	12.58	0.00	0.00	0.00	0.00	0.00	467.54	2,396.58
2020	1.00	21.45	11.66	0.00	0.00	0.00	0.00	0.00	433.15	2,636.98
2021	1.00	19.76	10.74	0.00	0.00	0.00	0.00	0.00	399.09	2,837.47
2022	1.00	18.26	9.92	0.00	0.00	0.00	0.00	0.00	368.77	3,005.18
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		210.16	114.21	0.00	0.00	0.00	0.00	0.00	4,244.23	3,005.18

Major Phase :	Oil			Abandonment Date :	1/1/2023
Perfs :	8065 - 8070			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	697.29	bbl/month		Revenue Int :	0.81243864	PW	5.00% :	3,545.52
Abandonment :	358.22	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	3,005.18
Initial Decline :	7.60	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	2,582.24
Beg Ratio :	4.211			Years to Payout :	0.00	PW	20.00% :	2,247.16
End Ratio :	3.539			Internal ROR (%) :	0.00	PW	25.00% :	1,978.46
						PW	30.00% :	1,760.42

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

29

This Page Is Intentionally Left Blank

Proved Shut-InEconomic Detailed Report

Date :     08/21/2014 11:45:32AM
		ECONOMIC SUMMARY PROJECTION		Proved Shut-In Rsv Class & Category
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	FISHERS REEF Field
Partner :	All Cases	Discount Rate (%) :	10.00
Case Type :	REPORT BREAK TOTAL CASE	All Cases
Cum Oil (Mbbl) :	95.65	SEC REPORT
Cum Gas (MMcf) :	349.56

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.18	0.48	0.14	0.34	109.34	5.79	15.58	1.98	0.00
2015	0.34	0.94	0.28	0.66	109.34	5.79	30.18	3.84	0.00
2016	0.26	0.71	0.21	0.50	109.34	5.79	22.70	2.88	0.00
2017	0.19	0.53	0.16	0.37	109.34	5.79	16.97	2.16	0.00
2018	0.14	0.40	0.12	0.28	109.34	5.79	12.73	1.62	0.00
2019	0.11	0.30	0.09	0.21	109.34	5.79	9.55	1.21	0.00
2020	0.08	0.22	0.07	0.16	109.34	5.79	7.18	0.91	0.00
2021	0.03	0.09	0.03	0.07	109.34	5.79	3.01	0.38	0.00

Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	1.33	3.67	1.08	2.59	109.34	5.79	117.91	14.98	0.00
Ult	96.98	353.23

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.87	0.44	0.00	0.00	0.00	0.00	0.00	16.26	15.92
2015	1.00	1.68	0.85	0.00	0.00	0.00	0.00	0.00	31.49	44.73
2016	1.00	1.26	0.64	0.00	0.00	0.00	0.00	0.00	23.68	64.34
2017	1.00	0.94	0.48	0.00	0.00	0.00	0.00	0.00	17.71	77.61
2018	1.00	0.71	0.36	0.00	0.00	0.00	0.00	0.00	13.28	86.63
2019	1.00	0.53	0.27	0.00	0.00	0.00	0.00	0.00	9.96	92.75
2020	1.00	0.40	0.20	0.00	0.00	0.00	0.00	0.00	7.49	96.91
2021	0.00	0.17	0.08	0.00	0.00	0.00	0.00	0.00	3.14	98.53
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		6.55	3.32	0.00	0.00	0.00	0.00	0.00	123.02	98.53

		Present Worth Profile (M$)
		PW	5.00% :	109.65
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	98.53
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	89.21
Years to Payout :	0.00	PW	20.00% :	81.34
Internal ROR (%) :	0.00	PW	25.00% :	74.63
		PW	30.00% :	68.87

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

30

Date : 08/21/2014 11:45:32 AM
		ECONOMIC PROJECTION
		As Of Date :	07/31/2014	Case	:	RFRU 1 112 (12528) - GBE
Project Name :	HYDROCARB ENERGY 06/30/2014	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Shut-In
Partner :	All Cases	All Cases		Field	:	FISHERS REEF
Case Type :	LEASE CASE			Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :	RED.07.14	SEC REPORT		Reservoir	:	FRIO 6 C
				Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :	95.65
Cum Gas (MMcf) :	349.56

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.18	0.48	0.14	0.34	109.34	5.79	15.58	1.98	0.00
2015	0.34	0.94	0.28	0.66	109.34	5.79	30.18	3.84	0.00
2016	0.26	0.71	0.21	0.50	109.34	5.79	22.70	2.88	0.00
2017	0.19	0.53	0.16	0.37	109.34	5.79	16.97	2.16	0.00
2018	0.14	0.40	0.12	0.28	109.34	5.79	12.73	1.62	0.00
2019	0.11	0.30	0.09	0.21	109.34	5.79	9.55	1.21	0.00
2020	0.08	0.22	0.07	0.16	109.34	5.79	7.18	0.91	0.00
2021	0.03	0.09	0.03	0.07	109.34	5.79	3.01	0.38	0.00

Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	1.33	3.67	1.08	2.59	109.34	5.79	117.91	14.98	0.00
Ult	96.98	353.23

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.87	0.44	0.00	0.00	0.00	0.00	0.00	16.26	15.92
2015	1.00	1.68	0.85	0.00	0.00	0.00	0.00	0.00	31.49	44.73
2016	1.00	1.26	0.64	0.00	0.00	0.00	0.00	0.00	23.68	64.34
2017	1.00	0.94	0.48	0.00	0.00	0.00	0.00	0.00	17.71	77.61
2018	1.00	0.71	0.36	0.00	0.00	0.00	0.00	0.00	13.28	86.63
2019	1.00	0.53	0.27	0.00	0.00	0.00	0.00	0.00	9.96	92.75
2020	1.00	0.40	0.20	0.00	0.00	0.00	0.00	0.00	7.49	96.91
2021	0.00	0.17	0.08	0.00	0.00	0.00	0.00	0.00	3.14	98.53
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		6.55	3.32	0.00	0.00	0.00	0.00	0.00	123.02	98.53

Major Phase :	Oil		Abandonment Date :	7/10/2021
Perfs :	8425 - 8428		Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	36.87	bbl/month	Revenue Int :	0.81045170	PW	5.00% :	109.65
Abandonment :	5.00	bbl/month	Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	98.53
Initial Decline :	25.00	% year       b =0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	89.21
Beg Ratio :	2.757		Years to Payout :	0.00	PW	20.00% :	81.34
End Ratio :	2.758		Internal ROR (%) :	0.00	PW	25.00% :	74.63
					PW	30.00% :	68.87

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

31

Date : 08/21/2014 11:45:32 AM
		ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Shut-In Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00	POINT BOLIVAR NORTH Field
Case Type :	REPORT BREAK TOTAL CASE	All Cases
Cum Oil (Mbbl) :	0.29	SEC REPORT
Cum Gas (MMcf) :	747.77

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	811.11	0.00	293.62	0.00	4.55	0.00	1,336.27	0.00
2016	0.00	458.42	0.00	165.95	0.00	4.55	0.00	755.23	0.00

Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	1,269.53	0.00	459.57	0.00	4.55	0.00	2,091.51	0.00
Ult	0.29	2,017.30

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	100.22	33.41	325.00	0.00	0.00	0.00	0.00	877.65	782.10
2016	1.00	56.64	18.88	0.00	0.00	0.00	0.00	0.00	679.71	1,349.47
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		156.86	52.29	325.00	0.00	0.00	0.00	0.00	1,557.36	1,349.47

		Present Worth Profile (M$)
		PW	5.00% :	1,449.26
Disc. Initial Invest. (M$) :	306.58	PW	10.00% :	1,349.47
ROInvestment (disc/undisc) :	5.40 / 5.79	PW	15.00% :	1,257.27
Years to Payout :	0.83	PW	20.00% :	1,172.03
Internal ROR (%) :	469.46	PW	25.00% :	1,093.16
		PW	30.00% :	1,020.13

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

32

Date : 08/21/2014 11:45:32 AM
ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 343 1 (Big Gas) - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Shut-In
Case Type :	LEASE CASE	All Cases		Field	:	POINT BOLIVAR NORTH
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	12300
Cum Oil (Mbbl) :	0.29			Co., State	:	GALVESTON, TX
Cum Gas (MMcf) :	747.77

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	811.11	0.00	293.62	0.00	4.55	0.00	1,336.27	0.00
2016	0.00	458.42	0.00	165.95	0.00	4.55	0.00	755.23	0.00

Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	1,269.53	0.00	459.57	0.00	4.55	0.00	2,091.51	0.00
Ult	0.29	2,017.30

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	100.22	33.41	325.00	0.00	0.00	0.00	0.00	877.65	782.10
2016	1.00	56.64	18.88	0.00	0.00	0.00	0.00	0.00	679.71	1,349.47
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		156.86	52.29	325.00	0.00	0.00	0.00	0.00	1,557.36	1,349.47

Major Phase :	Gas		Abandonment Date :	12/1/2016
Perfs :	13370 - 13427		Working Int :	0.50000000	Present Worth Profile (M$)
Initial Rate :	125,000.00	Mcf/month	Revenue Int :	0.36200000	PW	5.00% :	1,449.26
Abandonment :	26,214.47	Mcf/month	Disc. Initial Invest. (M$) :	306.58	PW	10.00% :	1,349.47
Initial Decline :	60.69	% year       b =0.000	ROInvestment (disc/undisc) :	5.40 / 5.79	PW	15.00% :	1,257.27
Beg Ratio :	0.000		Years to Payout :	0.83	PW	20.00% :	1,172.03
End Ratio :	0.000		Internal ROR (%) :	469.46	PW	25.00% :	1,093.16
					PW	30.00% :	1,020.13

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

33

Date :     08/21/2014 11:45:32AM
		ECONOMIC SUMMARY PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Shut-In Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00	RED FISH REEF Field
Case Type :	REPORT BREAK TOTAL CASE	All Cases
Cum Oil (Mbbl) :	863.59	SEC REPORT
Cum Gas (MMcf) :	8,495.30

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	2.02	22.27	1.63	16.31	109.29	4.00	178.43	65.24	0.00
2015	5.07	89.13	4.13	66.30	109.29	4.00	451.09	265.19	0.00
2016	4.66	105.60	3.82	79.13	109.29	4.00	417.53	316.52	0.00
2017	3.45	79.46	2.82	59.55	109.29	4.00	308.55	238.20	0.00
2018	2.66	61.42	2.17	46.03	109.29	4.00	237.60	184.12	0.00
2019	2.16	49.82	1.76	37.31	109.29	4.00	192.68	149.25	0.00
2020	1.76	40.55	1.43	30.35	109.29	4.00	156.79	121.39	0.00
2021	1.42	32.85	1.16	24.57	109.29	4.00	127.02	98.27	0.00
2022	1.16	26.72	0.95	19.97	109.29	4.00	103.32	79.88	0.00
2023	0.94	21.75	0.77	16.25	109.29	4.00	84.11	64.99	0.00
2024	0.77	17.77	0.63	13.26	109.29	4.00	68.71	53.06	0.00
2025	0.59	12.44	0.48	9.29	109.29	4.00	52.76	37.14	0.00
2026	0.43	7.54	0.35	5.58	109.29	4.00	38.40	22.32	0.00
2027	0.35	6.08	0.29	4.49	109.29	4.00	31.32	17.98	0.00
2028	0.28	4.68	0.23	3.44	109.29	4.00	24.80	13.77	0.00

Rem	0.32	3.81	0.25	2.72	109.29	4.00	27.45	10.89	0.00
Total	28.06	581.89	22.88	434.56	109.29	4.00	2,500.56	1,738.22	0.00
Ult	891.65	9,077.19

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	5.00	13.10	6.09	0.00	0.00	0.00	10.98	0.00	213.49	209.19
2015	5.00	40.64	17.91	150.00	0.00	0.00	39.36	0.00	468.38	633.11
2016	5.00	42.95	18.35	0.00	0.00	0.00	45.49	0.00	627.26	1,152.45
2017	4.00	32.06	13.67	0.00	0.00	0.00	34.64	0.00	466.39	1,502.18
2018	4.00	24.74	10.54	0.00	0.00	0.00	27.03	0.00	359.41	1,745.89
2019	4.00	20.06	8.55	0.00	0.00	0.00	21.98	0.00	291.35	1,924.72
2020	4.00	16.32	6.95	0.00	0.00	0.00	17.93	0.00	236.98	2,056.39
2021	4.00	13.21	5.63	0.00	0.00	0.00	14.56	0.00	191.89	2,152.89
2022	4.00	10.74	4.58	0.00	0.00	0.00	11.87	0.00	156.00	2,223.91
2023	4.00	8.74	3.73	0.00	0.00	0.00	9.69	0.00	126.94	2,276.23
2024	4.00	7.14	3.04	0.00	0.00	0.00	7.93	0.00	103.65	2,314.89
2025	3.00	5.21	2.25	0.00	0.00	0.00	5.71	0.00	76.73	2,340.81
2026	2.00	3.44	1.52	0.00	0.00	0.00	3.57	0.00	52.19	2,356.77
2027	2.00	2.79	1.23	0.00	0.00	0.00	2.89	0.00	42.38	2,368.50
2028	1.00	2.17	0.96	0.00	0.00	0.00	2.26	0.00	33.17	2,376.83
Rem.		2.08	0.96	0.00	0.00	0.00	2.16	0.00	33.14	7.21
Total		245.39	105.97	150.00	0.00	0.00	258.06	0.00	3,479.35	2,384.04

		Present Worth Profile (M$)
		PW	5.00% :	2,844.99
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	2,384.04
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	2,038.32
Years to Payout :	0.00	PW	20.00% :	1,771.69
Internal ROR (%) :	0.00	PW	25.00% :	1,561.02
		PW	30.00% :	1,391.07

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

34

Date : 08/21/2014 11:45:32AM
		ECONOMIC PROJECTION		Case	:	RFRU 247 21 (08946) - GBE
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Reserve Cat.	:	Proved Shut-In
Partner :	All Cases	Discount Rate (%) :	10.00	Field	:	RED FISH REEF
Case Type :	LEASE CASE	All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :	RED.07.14			Reservoir	:	FRIO 2-B
		SEC REPORT		Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :	444.79
Cum Gas (MMcf) :	2,962.57

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	1.10	7.71	0.88	5.51	109.29	4.00	95.81	22.05	0.00
2015	2.30	16.49	1.83	11.78	109.29	4.00	199.69	47.14	0.00
2016	1.92	14.28	1.53	10.20	109.29	4.00	166.81	40.82	0.00
2017	1.60	12.30	1.27	8.79	109.29	4.00	138.58	35.16	0.00
2018	1.33	10.62	1.06	7.59	109.29	4.00	115.48	30.37	0.00
2019	1.11	9.17	0.88	6.56	109.29	4.00	96.22	26.23	0.00
2020	0.93	7.94	0.74	5.68	109.29	4.00	80.38	22.71	0.00
2021	0.77	6.84	0.61	4.89	109.29	4.00	66.78	19.56	0.00
2022	0.64	5.91	0.51	4.22	109.29	4.00	55.64	16.90	0.00
2023	0.53	5.11	0.42	3.65	109.29	4.00	46.37	14.60	0.00
2024	0.45	4.42	0.35	3.16	109.29	4.00	38.73	12.64	0.00
2025	0.37	3.81	0.29	2.72	109.29	4.00	32.18	10.89	0.00
2026	0.31	3.29	0.25	2.35	109.29	4.00	26.81	9.40	0.00
2027	0.26	2.84	0.20	2.03	109.29	4.00	22.34	8.12	0.00
2028	0.22	2.46	0.17	1.76	109.29	4.00	18.66	7.03	0.00
Rem	0.32	3.81	0.25	2.72	109.29	4.00	27.45	10.89	0.00
Total	14.15	117.00	11.24	83.63	109.29	4.00	1,227.94	334.51	0.00
Ult	458.94	3,079.58

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	6.06	2.95	0.00	0.00	0.00	5.53	0.00	103.33	101.21
2015	1.00	12.72	6.17	0.00	0.00	0.00	11.67	0.00	216.27	298.87
2016	1.00	10.73	5.19	0.00	0.00	0.00	9.93	0.00	181.78	449.25
2017	1.00	9.01	4.34	0.00	0.00	0.00	8.40	0.00	151.98	563.05
2018	1.00	7.59	3.65	0.00	0.00	0.00	7.14	0.00	127.47	649.46
2019	1.00	6.39	3.06	0.00	0.00	0.00	6.06	0.00	106.94	715.08
2020	1.00	5.40	2.58	0.00	0.00	0.00	5.16	0.00	89.95	765.04
2021	1.00	4.54	2.16	0.00	0.00	0.00	4.38	0.00	75.27	802.89
2022	1.00	3.83	1.81	0.00	0.00	0.00	3.72	0.00	63.18	831.64
2023	1.00	3.23	1.52	0.00	0.00	0.00	3.17	0.00	53.04	853.50
2024	1.00	2.73	1.28	0.00	0.00	0.00	2.70	0.00	44.66	870.15
2025	1.00	2.30	1.08	0.00	0.00	0.00	2.29	0.00	37.40	882.78
2026	1.00	1.94	0.91	0.00	0.00	0.00	1.95	0.00	31.42	892.38
2027	1.00	1.64	0.76	0.00	0.00	0.00	1.66	0.00	26.40	899.68
2028	1.00	1.39	0.64	0.00	0.00	0.00	1.42	0.00	22.25	905.25
Rem.		2.08	0.96	0.00	0.00	0.00	2.16	0.00	33.14	7.21
Total		81.57	39.06	0.00	0.00	0.00	77.34	0.00	1,364.48	912.47

Major Phase :	Oil			Abandonment Date :	12/1/2030
Perfs :	8700 - 8707			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	226.56	bbl/month		Revenue Int :	0.79416670	PW	5.00% :	1,097.96
Abandonment :	11.49	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	912.47
Initial Decline :	16.68	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	778.17
Beg Ratio :	6.937			Years to Payout :	0.00	PW	20.00% :	677.46
End Ratio :	12.486			Internal ROR (%) :	0.00	PW	25.00% :	599.59
						PW	30.00% :	537.77

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

35

Date :    08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 224 176 - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Shut-In
Case Type :	LEASE CASE	All Cases		Field	:	RED FISH REEF
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	FB A-3 FRIO 6
Cum Oil (Mbbl) :	315.97			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	876.25

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.15	7.35	0.12	5.59	109.29	4.00	13.57	22.35	0.00
2016	0.51	25.47	0.43	19.37	109.29	4.00	47.03	77.47	0.00
2017	0.41	20.31	0.34	15.45	109.29	4.00	37.52	61.79	0.00
2018	0.33	16.25	0.27	12.36	109.29	4.00	30.02	49.44	0.00
2019	0.26	13.00	0.22	9.89	109.29	4.00	24.02	39.56	0.00
2020	0.21	10.43	0.18	7.93	109.29	4.00	19.27	31.73	0.00
2021	0.17	8.32	0.14	6.33	109.29	4.00	15.37	25.31	0.00
2022	0.13	6.66	0.11	5.06	109.29	4.00	12.30	20.25	0.00
2023	0.11	5.33	0.09	4.05	109.29	4.00	9.84	16.20	0.00
2024	0.09	4.27	0.07	3.25	109.29	4.00	7.89	13.00	0.00
2025	0.07	3.41	0.06	2.59	109.29	4.00	6.29	10.37	0.00
2026	0.00	0.20	0.00	0.15	109.29	4.00	0.37	0.60	0.00
Rem	0.00	0.00	0.00	0.00	0.	00	0.00	0.00	0.00
Total	2.42	121.00	2.04	92.02	109.29	4.00	223.48	368.08	0.00
Ult	318.39	997.25

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	2.30	0.90	50.00	0.00	0.00	3.09	0.00	-20.36	-18.45
2016	1.00	7.97	3.11	0.00	0.00	0.00	10.70	0.00	102.72	66.56
2017	1.00	6.36	2.48	0.00	0.00	0.00	8.53	0.00	81.94	127.93
2018	1.00	5.09	1.99	0.00	0.00	0.00	6.83	0.00	65.56	172.39
2019	1.00	4.07	1.59	0.00	0.00	0.00	5.46	0.00	52.45	204.59
2020	1.00	3.27	1.27	0.00	0.00	0.00	4.38	0.00	42.07	227.97
2021	1.00	2.61	1.02	0.00	0.00	0.00	3.50	0.00	33.56	244.85
2022	1.00	2.08	0.81	0.00	0.00	0.00	2.80	0.00	26.85	257.08
2023	1.00	1.67	0.65	0.00	0.00	0.00	2.24	0.00	21.49	265.93
2024	1.00	1.34	0.52	0.00	0.00	0.00	1.79	0.00	17.23	272.36
2025	1.00	1.07	0.42	0.00	0.00	0.00	1.43	0.00	13.75	277.00
2026	0.00	0.06	0.02	0.00	0.00	0.00	0.08	0.00	0.80	277.26
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		37.89	14.79	50.00	0.00	0.00	50.83	0.00	438.05	277.26

Major Phase :	Oil			Abandonment Date :	1/23/2026
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	50.00	bbl/month		Revenue Int :	0.84500000	PW	5.00% :	345.90
Abandonment :	5.00	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	277.26
Initial Decline :	20.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	225.20
Beg Ratio :	50.000			Years to Payout :	0.00	PW	20.00% :	185.03
End Ratio :	50.000			Internal ROR (%) :	0.00	PW	25.00% :	153.56
						PW	30.00% :	128.56

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

36

Date : 08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 225 050 - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Shut-In
Case Type :	LEASE CASE	All Cases		Field	:	RED FISH REEF
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	F-4&5
Cum Oil (Mbbl) :	76.47			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	197.20

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.79	26.36	0.67	20.05	109.29	4.00	73.04	80.19	0.00
2016	1.13	37.82	0.96	28.76	109.29	4.00	104.78	115.04	0.00
2017	0.91	30.17	0.76	22.94	109.29	4.00	83.58	91.77	0.00
2018	0.72	24.14	0.61	18.36	109.29	4.00	66.87	73.43	0.00
2019	0.58	19.31	0.49	14.69	109.29	4.00	53.51	58.75	0.00
2020	0.46	15.49	0.39	11.78	109.29	4.00	42.92	47.12	0.00
2021	0.37	12.36	0.31	9.40	109.29	4.00	34.23	37.59	0.00
2022	0.30	9.89	0.25	7.52	109.29	4.00	27.39	30.08	0.00
2023	0.24	7.91	0.20	6.02	109.29	4.00	21.92	24.06	0.00
2024	0.19	6.34	0.16	4.83	109.29	4.00	17.58	19.30	0.00
2025	0.15	5.06	0.13	3.85	109.29	4.00	14.02	15.40	0.00
2026	0.12	4.05	0.10	3.08	109.29	4.00	11.22	12.32	0.00
2027	0.10	3.24	0.08	2.46	109.29	4.00	8.98	9.86	0.00
2028	0.07	2.22	0.06	1.68	109.29	4.00	6.14	6.74	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	6.13	204.35	5.18	155.41	109.29	4.00	566.16	621.64	0.00
Ult	82.60	401.55

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	9.37	3.83	50.00	0.00	0.00	10.01	0.00	80.02	70.27
2016	1.00	13.45	5.50	0.00	0.00	0.00	14.36	0.00	186.52	224.63
2017	1.00	10.73	4.38	0.00	0.00	0.00	11.45	0.00	148.78	336.09
2018	1.00	8.58	3.51	0.00	0.00	0.00	9.16	0.00	119.04	416.81
2019	1.00	6.87	2.81	0.00	0.00	0.00	7.33	0.00	95.25	475.29
2020	1.00	5.51	2.25	0.00	0.00	0.00	5.88	0.00	76.40	517.74
2021	1.00	4.39	1.80	0.00	0.00	0.00	4.69	0.00	60.94	548.39
2022	1.00	3.52	1.44	0.00	0.00	0.00	3.75	0.00	48.76	570.59
2023	1.00	2.81	1.15	0.00	0.00	0.00	3.00	0.00	39.01	586.68
2024	1.00	2.26	0.92	0.00	0.00	0.00	2.41	0.00	31.29	598.35
2025	1.00	1.80	0.74	0.00	0.00	0.00	1.92	0.00	24.96	606.78
2026	1.00	1.44	0.59	0.00	0.00	0.00	1.54	0.00	19.97	612.89
2027	1.00	1.15	0.47	0.00	0.00	0.00	1.23	0.00	15.98	617.31
2028	0.00	0.79	0.32	0.00	0.00	0.00	0.84	0.00	10.92	620.07
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		72.67	29.70	50.00	0.00	0.00	77.58	0.00	957.86	620.07

Major Phase :	Gas			Abandonment Date :	11/1/2028
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	4,000.00	Mcf/month		Revenue Int :	0.84500000	PW	5.00% :	762.37
Abandonment :	200.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	620.07
Initial Decline :	20.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	513.55
Beg Ratio :	0.030			Years to Payout :	0.00	PW	20.00% :	431.80
End Ratio :	0.030			Internal ROR (%) :	0.00	PW	25.00% :	367.66
						PW	30.00% :	316.35

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

37

Date : 08/21/2014 11:45:32AM		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 247 175-L - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Shut-In
Case Type :	LEASE CASE	All Cases		Field	:	RED FISH REEF
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	FB B-1 FRIO 9
Cum Oil (Mbbl) :	7.87			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	1,406.15

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.54	16.73	0.45	12.41	109.29	4.00	48.95	49.65	0.00
2016	0.50	16.31	0.41	12.10	109.29	4.00	44.98	48.40	0.00
2017	0.37	13.01	0.31	9.65	109.29	4.00	33.64	38.60	0.00
2018	0.28	10.41	0.23	7.72	109.29	4.00	25.23	30.89	0.00
2019	0.21	8.33	0.17	6.18	109.29	4.00	18.93	24.71	0.00
2020	0.16	6.68	0.13	4.96	109.29	4.00	14.23	19.82	0.00
2021	0.12	5.33	0.10	3.95	109.29	4.00	10.64	15.81	0.00
2022	0.09	4.26	0.07	3.16	109.29	4.00	7.98	12.65	0.00
2023	0.07	3.41	0.05	2.53	109.29	4.00	5.99	10.12	0.00
2024	0.05	2.74	0.04	2.03	109.29	4.00	4.50	8.12	0.00
2025	0.00	0.17	0.00	0.12	109.29	4.00	0.26	0.49	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	2.39	87.39	1.97	64.82	109.29	4.00	215.35	259.28	0.00
Ult	10.26	1,493.54

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	5.98	2.47	50.00	0.00	0.00	6.27	0.00	33.89	28.87
2016	1.00	5.70	2.33	0.00	0.00	0.00	6.12	0.00	79.23	94.46
2017	1.00	4.44	1.81	0.00	0.00	0.00	4.88	0.00	61.12	140.25
2018	1.00	3.48	1.40	0.00	0.00	0.00	3.90	0.00	47.34	172.36
2019	1.00	2.72	1.09	0.00	0.00	0.00	3.12	0.00	36.70	194.90
2020	1.00	2.14	0.85	0.00	0.00	0.00	2.51	0.00	28.56	210.77
2021	1.00	1.68	0.66	0.00	0.00	0.00	2.00	0.00	22.12	221.90
2022	1.00	1.32	0.52	0.00	0.00	0.00	1.60	0.00	17.21	229.74
2023	1.00	1.03	0.40	0.00	0.00	0.00	1.28	0.00	13.40	235.26
2024	1.00	0.82	0.32	0.00	0.00	0.00	1.03	0.00	10.47	239.16
2025	0.00	0.05	0.02	0.00	0.00	0.00	0.06	0.00	0.63	239.39
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		29.35	11.87	50.00	0.00	0.00	32.76	0.00	350.64	239.39

Major Phase :	Gas			Abandonment Date :	1/25/2025
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	1,825.00	Mcf/month		Revenue Int :	0.82416670	PW	5.00% :	287.85
Abandonment :	200.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	239.39
Initial Decline :	20.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	201.36
Beg Ratio :	0.033			Years to Payout :	0.00	PW	20.00% :	171.07
End Ratio :	0.018			Internal ROR (%) :	0.00	PW	25.00% :	146.59
						PW	30.00% :	126.55

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

38

Date : 08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 247 198 (190463) F 10 Stray - GB
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Shut-In
Case Type :	LEASE CASE	All Cases		Field	:	RED FISH REEF
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	FB A FRIO 10 STRAY
Cum Oil (Mbbl) :	18.48			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	3,053.13

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.92	14.55	0.76	10.80	109.29	4.00	82.62	43.18	0.00
2015	1.29	22.20	1.06	16.46	109.29	4.00	115.85	65.85	0.00
2016	0.60	11.73	0.49	8.70	109.29	4.00	53.93	34.80	0.00
2017	0.17	3.67	0.14	2.72	109.29	4.00	15.24	10.88	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	2.97	52.15	2.45	38.68	109.29	4.00	267.63	154.72	0.00
Ult	21.46	3,105.28

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	7.04	3.14	0.00	0.00	0.00	5.46	0.00	110.16	107.98
2015	1.00	10.27	4.54	0.00	0.00	0.00	8.32	0.00	158.57	253.55
2016	1.00	5.09	2.22	0.00	0.00	0.00	4.40	0.00	77.02	317.55
2017	0.00	1.52	0.65	0.00	0.00	0.00	1.38	0.00	22.57	334.86
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		23.91	10.56	0.00	0.00	0.00	19.55	0.00	368.32	334.86

Major Phase :	Gas			Abandonment Date :	7/7/2017
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	3,276.54	Mcf/month		Revenue Int :	0.82416700	PW	5.00% :	350.91
Abandonment :	500.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	334.86
Initial Decline :	47.29	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	320.04
Beg Ratio :	0.065			Years to Payout :	0.00	PW	20.00% :	306.33
End Ratio :	0.045			Internal ROR (%) :	0.00	PW	25.00% :	293.62
						PW	30.00% :	281.83

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

39

Date :     08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Shut-In Rsv Class & Category
Partner :	All Cases	Discount Rate (%) :	10.00	TRINITY BAY Field
Case Type :	REPORT BREAK TOTAL CASE	All Cases
		SEC REPORT
Cum Oil (Mbbl) :	270.34
Cum Gas (MMcf) :	174.13

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	4.98	0.00	4.05	0.00	109.29	0.00	442.25	0.00	0.00
2015	11.99	0.00	9.74	0.00	109.29	0.00	1,064.45	0.00	0.00
2016	10.06	0.00	8.18	0.00	109.29	0.00	893.49	0.00	0.00
2017	8.41	0.00	6.83	0.00	109.29	0.00	746.37	0.00	0.00
2018	7.05	0.00	5.73	0.00	109.29	0.00	625.73	0.00	0.00
2019	5.91	0.00	4.80	0.00	109.29	0.00	524.91	0.00	0.00
2020	4.97	0.00	4.04	0.00	109.29	0.00	441.70	0.00	0.00
2021	4.17	0.00	3.38	0.00	109.29	0.00	369.85	0.00	0.00
2022	3.50	0.00	2.84	0.00	109.29	0.00	310.79	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	61.04	0.00	49.59	0.00	109.29	0.00	5,419.56	0.00	0.00
Ult	331.38	174.13

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	3.00	20.34	11.06	50.00	0.00	0.00	0.00	0.00	360.85	352.50
2015	3.00	48.96	26.61	0.00	0.00	0.00	0.00	0.00	988.88	1,256.31
2016	3.00	41.10	22.34	0.00	0.00	0.00	0.00	0.00	830.05	1,942.99
2017	3.00	34.33	18.66	0.00	0.00	0.00	0.00	0.00	693.38	2,462.20
2018	3.00	28.78	15.64	0.00	0.00	0.00	0.00	0.00	581.31	2,856.25
2019	3.00	24.15	13.12	0.00	0.00	0.00	0.00	0.00	487.64	3,155.50
2020	3.00	20.32	11.04	0.00	0.00	0.00	0.00	0.00	410.34	3,383.42
2021	3.00	17.01	9.25	0.00	0.00	0.00	0.00	0.00	343.59	3,556.17
2022	3.00	14.30	7.77	0.00	0.00	0.00	0.00	0.00	288.72	3,687.57
2023	3.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	3,687.57
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		249.30	135.49	50.00	0.00	0.00	0.00	0.00	4,984.77	3,687.57

		Present Worth Profile (M$)
		PW	5.00% :	4,260.12
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	3,687.57
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	3,229.64
Years to Payout :	0.00	PW	20.00% :	2,858.93
Internal ROR (%) :	0.00	PW	25.00% :	2,555.31
		PW	30.00% :	2,303.80

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

40

Date :      08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	TBSU #1 063D - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Shut-In
Case Type :	LEASE CASE	All Cases		Field	:	TRINITY BAY
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	FRIO 7
Cum Oil (Mbbl) :	196.34			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	88.62

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	2.44	0.00	1.98	0.00	109.29	0.00	216.22	0.00	0.00
2015	5.14	0.00	4.18	0.00	109.29	0.00	456.62	0.00	0.00
2016	4.38	0.00	3.56	0.00	109.29	0.00	388.69	0.00	0.00
2017	3.71	0.00	3.01	0.00	109.29	0.00	329.06	0.00	0.00
2018	3.15	0.00	2.56	0.00	109.29	0.00	279.40	0.00	0.00
2019	2.67	0.00	2.17	0.00	109.29	0.00	237.24	0.00	0.00
2020	2.27	0.00	1.85	0.00	109.29	0.00	201.95	0.00	0.00
2021	1.93	0.00	1.56	0.00	109.29	0.00	170.96	0.00	0.00
2022	1.63	0.00	1.33	0.00	109.29	0.00	145.17	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	27.31	0.00	22.19	0.00	109.29	0.00	2,425.32	0.00	0.00
Ult	223.65	88.62

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	9.95	5.41	0.00	0.00	0.00	0.00	0.00	200.87	196.74
2015	1.00	21.00	11.42	0.00	0.00	0.00	0.00	0.00	424.20	584.40
2016	1.00	17.88	9.72	0.00	0.00	0.00	0.00	0.00	361.10	883.10
2017	1.00	15.14	8.23	0.00	0.00	0.00	0.00	0.00	305.70	1,111.98
2018	1.00	12.85	6.99	0.00	0.00	0.00	0.00	0.00	259.57	1,287.92
2019	1.00	10.91	5.93	0.00	0.00	0.00	0.00	0.00	220.40	1,423.15
2020	1.00	9.29	5.05	0.00	0.00	0.00	0.00	0.00	187.61	1,527.35
2021	1.00	7.86	4.27	0.00	0.00	0.00	0.00	0.00	158.83	1,607.19
2022	1.00	6.68	3.63	0.00	0.00	0.00	0.00	0.00	134.86	1,668.57
2023	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	1,668.57
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		111.56	60.63	0.00	0.00	0.00	0.00	0.00	2,253.12	1,668.57

Major Phase :	Oil			Abandonment Date :	1/1/2023
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	497.88	bbl/month		Revenue Int :	0.81243864	PW	5.00% :	1,926.21
Abandonment :	125.43	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	1,668.57
Initial Decline :	15.10	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	1,463.00
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	1,297.00
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	1,161.35
						PW	30.00% :	1,049.23

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

41

Date :      08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	TBSU #1 068 - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Shut-In
Case Type :	LEASE CASE	All Cases		Field	:	TRINITY BAY
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	FRIO 1
Cum Oil (Mbbl) :	65.83			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	85.51

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	1.46	0.00	1.19	0.00	109.29	0.00	130.05	0.00	0.00
2015	2.97	0.00	2.41	0.00	109.29	0.00	263.49	0.00	0.00
2016	2.38	0.00	1.93	0.00	109.29	0.00	211.34	0.00	0.00
2017	1.90	0.00	1.54	0.00	109.29	0.00	168.59	0.00	0.00
2018	1.52	0.00	1.23	0.00	109.29	0.00	134.89	0.00	0.00
2019	1.22	0.00	0.99	0.00	109.29	0.00	107.93	0.00	0.00
2020	0.97	0.00	0.79	0.00	109.29	0.00	86.57	0.00	0.00
2021	0.78	0.00	0.63	0.00	109.29	0.00	69.05	0.00	0.00
2022	0.62	0.00	0.51	0.00	109.29	0.00	55.25	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	13.82	0.00	11.23	0.00	109.29	0.00	1,227.16	0.00	0.00
Ult	79.65	85.51

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	5.98	3.25	0.00	0.00	0.00	0.00	0.00	120.82	118.34
2015	1.00	12.12	6.59	0.00	0.00	0.00	0.00	0.00	244.79	342.15
2016	1.00	9.72	5.28	0.00	0.00	0.00	0.00	0.00	196.34	504.64
2017	1.00	7.75	4.21	0.00	0.00	0.00	0.00	0.00	156.62	621.96
2018	1.00	6.20	3.37	0.00	0.00	0.00	0.00	0.00	125.31	706.94
2019	1.00	4.96	2.70	0.00	0.00	0.00	0.00	0.00	100.26	768.49
2020	1.00	3.98	2.16	0.00	0.00	0.00	0.00	0.00	80.42	813.18
2021	1.00	3.18	1.73	0.00	0.00	0.00	0.00	0.00	64.15	845.44
2022	1.00	2.54	1.38	0.00	0.00	0.00	0.00	0.00	51.33	868.81
2023	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	868.81
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		56.45	30.68	0.00	0.00	0.00	0.00	0.00	1,140.03	868.81

Major Phase :	Oil			Abandonment Date :	1/1/2023
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	303.13	bbl/month		Revenue Int :	0.81243864	PW	5.00% :	989.26
Abandonment :	46.29	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	868.81
Initial Decline :	20.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	771.41
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	691.71
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	625.74
						PW	30.00% :	570.53

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

42

Date :      08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	TBSU #1 133 - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Shut-In
Case Type :	LEASE CASE	All Cases		Field	:	TRINITY BAY
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	Frio 12
Cum Oil (Mbbl) :	8.18			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	1.08	0.00	0.88	0.00	109.29	0.00	95.98	0.00	0.00
2015	3.88	0.00	3.15	0.00	109.29	0.00	344.33	0.00	0.00
2016	3.30	0.00	2.69	0.00	109.29	0.00	293.46	0.00	0.00
2017	2.80	0.00	2.28	0.00	109.29	0.00	248.73	0.00	0.00
2018	2.38	0.00	1.93	0.00	109.29	0.00	211.44	0.00	0.00
2019	2.02	0.00	1.64	0.00	109.29	0.00	179.74	0.00	0.00
2020	1.73	0.00	1.40	0.00	109.29	0.00	153.19	0.00	0.00
2021	1.46	0.00	1.19	0.00	109.29	0.00	129.84	0.00	0.00
2022	1.24	0.00	1.01	0.00	109.29	0.00	110.37	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	19.90	0.00	16.17	0.00	109.29	0.00	1,767.08	0.00	0.00
Ult	28.08	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	4.42	2.40	50.00	0.00	0.00	0.00	0.00	39.17	37.42
2015	1.00	15.84	8.61	0.00	0.00	0.00	0.00	0.00	319.89	329.75
2016	1.00	13.50	7.34	0.00	0.00	0.00	0.00	0.00	272.62	555.25
2017	1.00	11.44	6.22	0.00	0.00	0.00	0.00	0.00	231.07	728.26
2018	1.00	9.73	5.29	0.00	0.00	0.00	0.00	0.00	196.43	861.40
2019	1.00	8.27	4.49	0.00	0.00	0.00	0.00	0.00	166.98	963.86
2020	1.00	7.05	3.83	0.00	0.00	0.00	0.00	0.00	142.31	1,042.89
2021	1.00	5.97	3.25	0.00	0.00	0.00	0.00	0.00	120.62	1,103.53
2022	1.00	5.08	2.76	0.00	0.00	0.00	0.00	0.00	102.54	1,150.19
2023	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	1,150.19
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		81.29	44.18	50.00	0.00	0.00	0.00	0.00	1,591.62	1,150.19

Major Phase :	Oil			Abandonment Date :	1/1/2023
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	365.00	bbl/month		Revenue Int :	0.81243864	PW	5.00% :	1,344.65
Abandonment :	95.43	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	1,150.19
Initial Decline :	15.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	995.22
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	870.22
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	768.22
						PW	30.00% :	684.04

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

43

Proved Behind PipeEconomic Detailed Report

Date :	08/21/2014 11:45:32AM
			ECONOMIC SUMMARY PROJECTION
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Behind Pipe Rsv Class & Category
Partner :		All Cases	Discount Rate (%) :	10.00	FISHERS REEF Field
Case Type :		REPORT BREAK TOTAL CASE	All Cases
			SEC REPORT

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	19.96	399.21	11.21	195.06	109.34	5.79	1,225.73	1,130.21	0.00
2017	18.01	360.22	10.12	176.01	109.34	5.79	1,106.01	1,019.81	0.00
2018	13.71	308.92	7.76	155.72	109.34	5.79	847.99	902.29	0.00
2019	11.17	334.08	6.45	178.49	109.34	5.79	705.19	1,034.21	0.00
2020	8.20	241.72	4.73	128.81	109.34	5.79	517.22	746.37	0.00
2021	5.99	174.05	3.45	92.51	109.34	5.79	377.39	536.03	0.00
2022	4.39	125.80	2.53	66.70	109.34	5.79	276.32	386.46	0.00
2023	3.22	90.98	1.85	48.12	109.34	5.79	202.39	278.81	0.00
2024	2.37	66.00	1.36	34.82	109.34	5.79	148.62	201.74	0.00
2025	1.73	47.64	0.99	25.07	109.34	5.79	108.57	145.26	0.00
2026	1.27	34.52	0.73	18.12	109.34	5.79	79.58	105.00	0.00
2027	0.93	25.02	0.53	13.11	109.34	5.79	58.35	75.94	0.00
2028	0.69	18.19	0.39	9.51	109.34	5.79	42.90	55.09	0.00
Rem	0.27	7.09	0.15	3.70	109.34	5.79	16.85	21.43	0.00
Total	91.92	2,233.43	52.25	1,145.74	109.34	5.79	5,713.11	6,638.64	0.00
Ult	91.92	2,233.43

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.00	141.15	58.90	140.63	0.00	0.00	0.00	0.00	2,015.27	1,649.21
2017	1.00	127.36	53.15	0.00	0.00	0.00	0.00	0.00	1,945.31	3,107.41
2018	2.00	106.68	43.76	284.36	0.00	0.00	0.00	0.00	1,315.48	4,000.92
2019	2.00	110.00	43.48	0.00	0.00	0.00	0.00	0.00	1,585.91	4,975.29
2020	2.00	79.77	31.59	0.00	0.00	0.00	0.00	0.00	1,152.23	5,616.07
2021	2.00	57.56	22.84	0.00	0.00	0.00	0.00	0.00	833.02	6,035.39
2022	2.00	41.70	16.57	0.00	0.00	0.00	0.00	0.00	604.52	6,310.86
2023	2.00	30.22	12.03	0.00	0.00	0.00	0.00	0.00	438.94	6,491.93
2024	2.00	21.97	8.76	0.00	0.00	0.00	0.00	0.00	319.63	6,611.28
2025	2.00	15.89	6.35	0.00	0.00	0.00	0.00	0.00	231.59	6,689.55
2026	2.00	11.54	4.61	0.00	0.00	0.00	0.00	0.00	168.43	6,741.08
2027	2.00	8.38	3.36	0.00	0.00	0.00	0.00	0.00	122.56	6,775.03
2028	2.00	6.10	2.45	0.00	0.00	0.00	0.00	0.00	89.43	6,797.45
Rem.		2.38	0.96	0.00	0.00	0.00	0.00	0.00	34.94	8.11
Total		760.70	308.79	424.99	0.00	0.00	0.00	0.00	10,857.26	6,805.56

		Present Worth Profile (M$)
		PW	5.00% :	8,519.12
Disc. Initial Invest. (M$) :	120.09	PW	10.00% :	6,805.56
ROInvestment (disc/undisc) :	57.67 / 78.20	PW	15.00% :	5,520.59
Years to Payout :	1.63	PW	20.00% :	4,537.25
Internal ROR (%) :	>1000	PW	25.00% :	3,771.14
		PW	30.00% :	3,164.83

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

44

Date :	08/21/2014 11:45:32AM
			ECONOMIC PROJECTION
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 05-8A #01 (BP02) - GBE
Partner :		All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Behind Pipe
Case Type :		RECOMPLETION CASE	All Cases		Field	:	FISHERS REEF
Archive Set :		RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
			SEC REPORT		Reservoir	:	FRIO 15
Cum Oil (Mbbl) :		0.00			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.43	43.36	0.30	25.97	109.34	5.79	32.64	150.47	0.00
2019	1.38	138.31	0.95	82.84	109.34	5.79	104.11	479.97	0.00
2020	0.97	97.06	0.67	58.13	109.34	5.79	73.06	336.82	0.00
2021	0.68	67.74	0.47	40.57	109.34	5.79	50.99	235.07	0.00
2022	0.47	47.43	0.33	28.41	109.34	5.79	35.70	164.59	0.00
2023	0.33	33.21	0.23	19.89	109.34	5.79	25.00	115.24	0.00
2024	0.23	23.30	0.16	13.96	109.34	5.79	17.54	80.87	0.00
2025	0.16	16.26	0.11	9.74	109.34	5.79	12.24	56.44	0.00
2026	0.11	11.39	0.08	6.82	109.34	5.79	8.57	39.52	0.00
2027	0.08	7.97	0.05	4.78	109.34	5.79	6.00	27.67	0.00
2028	0.06	5.60	0.04	3.35	109.34	5.79	4.21	19.42	0.00
Rem	0.02	2.12	0.01	1.27	109.34	5.79	1.60	7.36	0.00
Total	4.94	493.76	3.40	295.72	109.34	5.79	371.65	1,713.43	0.00
Ult	4.94	493.76

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	1.00	12.79	4.58	284.36	0.00	0.00	0.00	0.00	-118.61	-79.66
2019	1.00	40.79	14.60	0.00	0.00	0.00	0.00	0.00	528.68	245.25
2020	1.00	28.62	10.25	0.00	0.00	0.00	0.00	0.00	371.01	451.64
2021	1.00	19.98	7.15	0.00	0.00	0.00	0.00	0.00	258.93	582.02
2022	1.00	13.99	5.01	0.00	0.00	0.00	0.00	0.00	181.29	664.65
2023	1.00	9.79	3.51	0.00	0.00	0.00	0.00	0.00	126.94	717.03
2024	1.00	6.87	2.46	0.00	0.00	0.00	0.00	0.00	89.08	750.30
2025	1.00	4.80	1.72	0.00	0.00	0.00	0.00	0.00	62.17	771.32
2026	1.00	3.36	1.20	0.00	0.00	0.00	0.00	0.00	43.53	784.64
2027	1.00	2.35	0.84	0.00	0.00	0.00	0.00	0.00	30.48	793.09
2028	1.00	1.65	0.59	0.00	0.00	0.00	0.00	0.00	21.39	798.45
Rem.		0.63	0.22	0.00	0.00	0.00	0.00	0.00	8.11	1.88
Total		145.60	52.13	284.36	0.00	0.00	0.00	0.00	1,602.99	800.33

Major Phase :	Gas			Abandonment Date :	7/1/2029
Perfs :	0 - 0			Working Int :	0.87500000	Present Worth Profile (M$)
Initial Rate :	15,000.00	Mcf/month		Revenue Int :	0.68840000	PW	5.00% :	1,126.03
Abandonment :	324.08	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	800.33
Initial Decline :	30.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	574.66
Beg Ratio :	0.010			Years to Payout :	0.00	PW	20.00% :	416.26
End Ratio :	0.010			Internal ROR (%) :	0.00	PW	25.00% :	303.84
						PW	30.00% :	223.24

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

45

Date :	08/21/2014 11:45:32AM		ECONOMIC PROJECTION
					Case	:	ST 06-7A #01 ST F-13 - GBE
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Reserve Cat.	:	Proved Behind Pipe
Partner :		All Cases	Discount Rate (%) :	10.00	Field	:	FISHERS REEF
Case Type :		LEASE CASE	All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :		RED.07.14			Reservoir	:	FRIO 13
			SEC REPORT		Co., State	:	CHAMBERS, TX

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	19.96	399.21	11.21	195.06	109.34	5.79	1,225.73	1,130.21	0.00
2017	18.01	360.22	10.12	176.01	109.34	5.79	1,106.01	1,019.81	0.00
2018	13.28	265.55	7.46	129.75	109.34	5.79	815.35	751.81	0.00
2019	9.79	195.77	5.50	95.65	109.34	5.79	601.08	554.24	0.00
2020	7.23	144.66	4.06	70.68	109.34	5.79	444.16	409.55	0.00
2021	5.32	106.31	2.99	51.94	109.34	5.79	326.40	300.96	0.00
2022	3.92	78.37	2.20	38.29	109.34	5.79	240.62	221.87	0.00
2023	2.89	57.77	1.62	28.23	109.34	5.79	177.39	163.57	0.00
2024	2.13	42.69	1.20	20.86	109.34	5.79	131.08	120.86	0.00
2025	1.57	31.37	0.88	15.33	109.34	5.79	96.33	88.82	0.00
2026	1.16	23.13	0.65	11.30	109.34	5.79	71.01	65.48	0.00
2027	0.85	17.05	0.48	8.33	109.34	5.79	52.35	48.27	0.00
2028	0.63	12.60	0.35	6.16	109.34	5.79	38.68	35.67	0.00
Rem	0.25	4.97	0.14	2.43	109.34	5.79	15.26	14.07	0.00
Total	86.98	1,739.67	48.85	850.02	109.34	5.79	5,341.46	4,925.20	0.00
Ult	86.98	1,739.67

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.00	141.15	58.90	140.63	0.00	0.00	0.00	0.00	2,015.27	1,649.21
2017	1.00	127.36	53.15	0.00	0.00	0.00	0.00	0.00	1,945.31	3,107.41
2018	1.00	93.89	39.18	0.00	0.00	0.00	0.00	0.00	1,434.10	4,080.57
2019	1.00	69.22	28.88	0.00	0.00	0.00	0.00	0.00	1,057.23	4,730.04
2020	1.00	51.15	21.34	0.00	0.00	0.00	0.00	0.00	781.22	5,164.43
2021	1.00	37.59	15.68	0.00	0.00	0.00	0.00	0.00	574.09	5,453.37
2022	1.00	27.71	11.56	0.00	0.00	0.00	0.00	0.00	423.23	5,646.21
2023	1.00	20.43	8.52	0.00	0.00	0.00	0.00	0.00	312.00	5,774.90
2024	1.00	15.09	6.30	0.00	0.00	0.00	0.00	0.00	230.55	5,860.97
2025	1.00	11.09	4.63	0.00	0.00	0.00	0.00	0.00	169.42	5,918.23
2026	1.00	8.18	3.41	0.00	0.00	0.00	0.00	0.00	124.90	5,956.44
2027	1.00	6.03	2.52	0.00	0.00	0.00	0.00	0.00	92.08	5,981.94
2028	1.00	4.45	1.86	0.00	0.00	0.00	0.00	0.00	68.04	5,998.99
Rem.		1.76	0.73	0.00	0.00	0.00	0.00	0.00	26.83	6.23
Total		615.10	256.67	140.63	0.00	0.00	0.00	0.00	9,254.27	6,005.22

Major Phase :	Gas			Abandonment Date :	7/1/2029
Perfs :	0 - 0			Working Int :	0.75000000	Present Worth Profile (M$)
Initial Rate :	45,000.00	Mcf/month		Revenue Int :	0.56162211	PW	5.00% :	7,393.09
Abandonment :	769.42	Mcf/month		Disc. Initial Invest. (M$) :	120.09	PW	10.00% :	6,005.22
Initial Decline :	26.29	% year	b = 0.000	ROInvestment (disc/undisc) :	51.00 / 66.81	PW	15.00% :	4,945.94
Beg Ratio :	0.050			Years to Payout :	1.63	PW	20.00% :	4,120.98
End Ratio :	0.050			Internal ROR (%) :	>1000	PW	25.00% :	3,467.30
						PW	30.00% :	2,941.58

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

46

Date :	08/21/2014 11:45:32AM
			ECONOMIC SUMMARY PROJECTION
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Proved Behind Pipe Rsv Class & Category
Partner :		All Cases	Discount Rate (%) :	10.00	RED FISH REEF Field
Case Type :		REPORT BREAK TOTAL CASE	All Cases
			SEC REPORT

Cum Oil (Mbbl) :	5.48
Cum Gas (MMcf) :	114.14

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	5.31	110.65	4.22	79.08	109.29	4.00	460.96	316.34	0.00
2015	11.37	387.32	9.06	280.08	109.29	4.00	989.71	1,120.32	0.00
2016	7.08	394.37	5.64	284.32	109.29	4.00	616.15	1,137.29	0.00
2017	6.36	811.37	5.13	584.21	109.29	4.00	560.44	2,336.84	0.00
2018	6.33	731.06	5.15	528.44	109.29	4.00	562.82	2,113.78	0.00
2019	4.04	454.13	3.29	328.46	109.29	4.00	359.52	1,313.84	0.00
2020	2.59	282.41	2.11	204.38	109.29	4.00	230.59	817.54	0.00
2021	1.65	174.93	1.35	126.69	109.29	4.00	147.34	506.75	0.00
2022	1.06	108.92	0.87	78.94	109.29	4.00	94.63	315.75	0.00
2023	0.68	66.70	0.55	48.36	109.29	4.00	60.18	193.43	0.00
2024	0.43	40.21	0.35	29.16	109.29	4.00	38.01	116.66	0.00
2025	0.26	24.91	0.22	18.08	109.29	4.00	23.54	72.33	0.00
2026	4.47	15.35	3.68	11.19	109.29	4.00	402.25	44.74	0.00
2027	20.42	11.34	16.83	8.38	109.29	4.00	1,839.12	33.52	0.00
2028	13.29	6.65	10.96	4.93	109.29	4.00	1,197.51	19.72	0.00
Rem	13.84	6.92	11.41	5.13	109.29	4.00	1,246.76	20.53	0.00
Total	99.20	3,627.23	80.79	2,619.85	109.29	4.00	8,829.51	10,479.39	0.00
Ult	104.68	3,741.37

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	3.00	44.93	19.43	0.00	0.00	0.00	40.74	0.00	672.20	658.32
2015	4.00	129.55	52.75	250.00	0.00	0.00	143.42	0.00	1,534.31	2,053.28
2016	5.00	113.64	43.84	250.00	0.00	0.00	145.81	0.00	1,200.16	3,042.67
2017	6.00	201.04	72.43	300.00	0.00	0.00	298.82	0.00	2,024.98	4,541.17
2018	6.00	184.42	66.92	0.00	0.00	0.00	268.88	0.00	2,156.38	6,006.34
2019	6.00	115.08	41.83	0.00	0.00	0.00	167.00	0.00	1,349.45	6,836.44
2020	6.00	71.92	26.20	0.00	0.00	0.00	103.84	0.00	846.16	7,307.57
2021	6.00	44.78	16.35	0.00	0.00	0.00	64.31	0.00	528.64	7,573.99
2022	6.00	28.03	10.26	0.00	0.00	0.00	40.04	0.00	332.05	7,725.47
2023	6.00	17.28	6.34	0.00	0.00	0.00	24.50	0.00	205.49	7,810.39
2024	5.00	10.50	3.87	0.00	0.00	0.00	14.76	0.00	125.54	7,857.32
2025	5.00	6.51	2.40	0.00	0.00	0.00	9.14	0.00	77.82	7,883.67
2026	3.00	21.86	11.17	50.00	0.00	0.00	5.63	0.00	358.33	7,989.03
2027	2.00	87.11	46.82	0.00	0.00	0.00	4.15	0.00	1,734.57	8,469.93
2028	1.00	56.56	30.43	0.00	0.00	0.00	2.43	0.00	1,127.80	8,752.94
Rem.		58.89	31.68	0.00	0.00	0.00	2.53	0.00	1,174.19	257.47
Total		1,192.11	482.72	850.00	0.00	0.00	1,336.00	0.00	15,448.07	9,010.41

		Present Worth Profile (M$)
		PW	5.00% :	11,495.64
Disc. Initial Invest. (M$) :	258.34	PW	10.00% :	9,010.41
ROInvestment (disc/undisc) :	35.88 / 45.14	PW	15.00% :	7,352.69
Years to Payout :	0.22	PW	20.00% :	6,183.73
Internal ROR (%) :	>1000	PW	25.00% :	5,318.61
		PW	30.00% :	4,652.59

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

47

Date :	08/21/2014 11:45:32AM
			ECONOMIC PROJECTION
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 225 187 - GBE
Partner :		All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Behind Pipe
Case Type :		LEASE CASE	All Cases		Field	:	RED FISH REEF
Archive Set :		RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
			SEC REPORT		Reservoir	:	FRIO 15 A & B
					Co., State	:	CHAMBERS, TX

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.09	173.07	0.89	126.95	109.29	4.00	97.12	507.79	0.00
2016	0.82	130.66	0.67	95.84	109.29	4.00	73.32	383.34	0.00
2017	0.50	78.78	0.40	57.78	109.29	4.00	44.21	231.13	0.00
2018	0.30	47.66	0.24	34.96	109.29	4.00	26.75	139.85	0.00
2019	0.18	28.84	0.15	21.15	109.29	4.00	16.18	84.61	0.00
2020	0.11	17.49	0.09	12.83	109.29	4.00	9.81	51.30	0.00
2021	0.07	10.54	0.05	7.73	109.29	4.00	5.92	30.93	0.00
2022	0.04	6.38	0.03	4.68	109.29	4.00	3.58	18.72	0.00
2023	0.02	2.61	0.01	1.92	109.29	4.00	1.47	7.66	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	3.12	496.03	2.55	363.84	109.29	4.00	278.35	1,455.34	0.00
Ult	3.12	496.03

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	42.55	15.12	250.00	0.00	0.00	64.53	0.00	232.70	202.33
2016	1.00	32.12	11.42	0.00	0.00	0.00	48.72	0.00	364.40	504.59
2017	1.00	19.37	6.88	0.00	0.00	0.00	29.37	0.00	219.71	669.56
2018	1.00	11.72	4.16	0.00	0.00	0.00	17.77	0.00	132.94	759.91
2019	1.00	7.09	2.52	0.00	0.00	0.00	10.75	0.00	80.43	809.40
2020	1.00	4.30	1.53	0.00	0.00	0.00	6.52	0.00	48.77	836.56
2021	1.00	2.59	0.92	0.00	0.00	0.00	3.93	0.00	29.40	851.39
2022	1.00	1.57	0.56	0.00	0.00	0.00	2.38	0.00	17.79	859.51
2023	1.00	0.64	0.23	0.00	0.00	0.00	0.97	0.00	7.29	862.57
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		121.95	43.34	250.00	0.00	0.00	184.96	0.00	1,133.44	862.57

Major Phase :	Gas			Abandonment Date :	8/13/2023
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	23,360.00	Mcf/month		Revenue Int :	0.81500000	PW	5.00% :	985.66
Abandonment :	300.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	862.57
Initial Decline :	100.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	759.06
Beg Ratio :	0.006			Years to Payout :	0.00	PW	20.00% :	671.26
End Ratio :	0.006			Internal ROR (%) :	0.00	PW	25.00% :	596.20
						PW	30.00% :	531.55

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

48

Date :	08/21/2014 11:45:32AM
			ECONOMIC PROJECTION
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 246 181 (BP01) - GBE
Partner :		All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Behind Pipe
Case Type :		LEASE CASE	All Cases		Field	:	RED FISH REEF
Archive Set :		RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
			SEC REPORT		Reservoir	:	FRIO 9
Cum Oil (Mbbl) :		5.48			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :		114.14

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	5.31	110.65	4.22	79.08	109.29	4.00	460.96	316.34	0.00
2015	10.28	214.25	8.17	153.13	109.29	4.00	892.59	612.54	0.00
2016	6.25	130.30	4.97	93.13	109.29	4.00	542.83	372.52	0.00
2017	3.77	78.56	2.99	56.15	109.29	4.00	327.30	224.61	0.00
2018	2.28	47.53	1.81	33.97	109.29	4.00	198.03	135.90	0.00
2019	1.38	28.76	1.10	20.56	109.29	4.00	119.82	82.22	0.00
2020	0.84	17.44	0.66	12.46	109.29	4.00	72.65	49.85	0.00
2021	0.50	10.51	0.40	7.51	109.29	4.00	43.80	30.06	0.00
2022	0.31	6.36	0.24	4.55	109.29	4.00	26.50	18.19	0.00
2023	0.18	3.85	0.15	2.75	109.29	4.00	16.04	11.00	0.00
2024	0.11	2.33	0.09	1.67	109.29	4.00	9.72	6.67	0.00
2025	0.06	1.18	0.04	0.84	109.29	4.00	4.90	3.36	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	31.28	651.72	24.84	465.81	109.29	4.00	2,715.14	1,863.26	0.00
Ult	36.76	765.85

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	44.93	19.43	0.00	0.00	0.00	40.74	0.00	672.20	658.32
2015	1.00	87.00	37.63	0.00	0.00	0.00	78.88	0.00	1,301.61	1,850.95
2016	1.00	52.91	22.88	0.00	0.00	0.00	47.97	0.00	791.59	2,507.56
2017	1.00	31.90	13.80	0.00	0.00	0.00	28.93	0.00	477.28	2,865.91
2018	1.00	19.30	8.35	0.00	0.00	0.00	17.50	0.00	288.78	3,062.18
2019	1.00	11.68	5.05	0.00	0.00	0.00	10.59	0.00	174.72	3,169.69
2020	1.00	7.08	3.06	0.00	0.00	0.00	6.42	0.00	105.94	3,228.69
2021	1.00	4.27	1.85	0.00	0.00	0.00	3.87	0.00	63.87	3,260.89
2022	1.00	2.58	1.12	0.00	0.00	0.00	2.34	0.00	38.65	3,278.53
2023	1.00	1.56	0.68	0.00	0.00	0.00	1.42	0.00	23.38	3,288.19
2024	1.00	0.95	0.41	0.00	0.00	0.00	0.86	0.00	14.18	3,293.49
2025	1.00	0.48	0.21	0.00	0.00	0.00	0.43	0.00	7.14	3,295.93
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		264.64	114.46	0.00	0.00	0.00	239.95	0.00	3,959.34	3,295.93

Major Phase :	Gas			Abandonment Date :	10/18/2025
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	22,351.44	Mcf/month		Revenue Int :	0.79416700	PW	5.00% :	3,598.19
Abandonment :	100.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	3,295.93
Initial Decline :	10.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	3,039.68
Beg Ratio :	0.048			Years to Payout :	0.00	PW	20.00% :	2,819.94
End Ratio :	0.048			Internal ROR (%) :	0.00	PW	25.00% :	2,629.56
						PW	30.00% :	2,463.13

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

49

Date :	08/21/2014 11:45:32AM
			ECONOMIC PROJECTION
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 247 023 (BP01) - GBE
Partner :		All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Behind Pipe
Case Type :		LEASE CASE	All Cases		Field	:	RED FISH REEF
Archive Set :		RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
			SEC REPORT		Reservoir	:	FRIO 9
Cum Oil (Mbbl) :		0.00			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	316.10	0.00	225.93	0.00	4.00	0.00	903.72	0.00
2018	0.00	300.64	0.00	214.88	0.00	4.00	0.00	859.54	0.00
2019	0.00	183.08	0.00	130.86	0.00	4.00	0.00	523.43	0.00
2020	0.00	111.00	0.00	79.34	0.00	4.00	0.00	317.34	0.00
2021	0.00	66.92	0.00	47.83	0.00	4.00	0.00	191.33	0.00
2022	0.00	40.49	0.00	28.94	0.00	4.00	0.00	115.75	0.00
2023	0.00	24.49	0.00	17.51	0.00	4.00	0.00	70.03	0.00
2024	0.00	14.85	0.00	10.61	0.00	4.00	0.00	42.46	0.00
2025	0.00	8.95	0.00	6.40	0.00	4.00	0.00	25.60	0.00
2026	0.00	5.42	0.00	3.87	0.00	4.00	0.00	15.49	0.00
2027	0.02	1.14	0.01	0.81	109.29	4.00	1.37	3.25	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.02	1,073.08	0.01	766.98	109.29	4.00	1.37	3,067.93	0.00
Ult	0.02	1,073.08

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	1.00	67.78	22.59	250.00	0.00	0.00	116.38	0.00	446.97	323.94
2018	1.00	64.47	21.49	0.00	0.00	0.00	110.69	0.00	662.89	774.38
2019	1.00	39.26	13.09	0.00	0.00	0.00	67.41	0.00	403.68	1,022.76
2020	1.00	23.80	7.93	0.00	0.00	0.00	40.87	0.00	244.74	1,159.07
2021	1.00	14.35	4.78	0.00	0.00	0.00	24.64	0.00	147.55	1,233.45
2022	1.00	8.68	2.89	0.00	0.00	0.00	14.91	0.00	89.27	1,274.19
2023	1.00	5.25	1.75	0.00	0.00	0.00	9.02	0.00	54.01	1,296.51
2024	1.00	3.18	1.06	0.00	0.00	0.00	5.47	0.00	32.74	1,308.75
2025	1.00	1.92	0.64	0.00	0.00	0.00	3.30	0.00	19.74	1,315.43
2026	1.00	1.16	0.39	0.00	0.00	0.00	1.99	0.00	11.94	1,319.09
2027	1.00	0.31	0.12	0.00	0.00	0.00	0.42	0.00	3.79	1,320.18
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		230.16	76.73	250.00	0.00	0.00	395.09	0.00	2,117.32	1,320.18

Major Phase :	Gas			Abandonment Date :	4/17/2027
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	32,850.00	Mcf/month		Revenue Int :	0.79416670	PW	5.00% :	1,665.26
Abandonment :	300.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	1,320.18
Initial Decline :	10.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	1,053.93
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	846.56
End Ratio :	0.020			Internal ROR (%) :	0.00	PW	25.00% :	683.70
						PW	30.00% :	554.84

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

50

Date :    08/21/2014 11:45:32AM			ECONOMIC PROJECTION		Case	:	ST 247 198 (190463) F 7A & 7B - GB
			As Of Date :	07/31/2014	Reserve Cat.	:	Proved Behind Pipe
Project Name :	HYDROCARB ENERGY 06/30/2014		Discount Rate (%) :	10.00	Field	:	RED FISH REEF
Partner :	All Cases		All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Case Type :	RECOMPLETION CASE				Reservoir	:	FB A FRIO 7A & 7B
Archive Set :	RED.07.14		SEC REPORT		Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :		0.00
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	4.35	2.18	3.59	1.61	109.29	4.00	391.90	6.45	0.00
2027	20.40	10.20	16.82	7.57	109.29	4.00	1,837.75	30.27	0.00
2028	13.29	6.65	10.96	4.93	109.29	4.00	1,197.51	19.72	0.00
Rem	13.84	6.92	11.41	5.13	109.29	4.00	1,246.76	20.53	0.00
Total	51.89	25.95	42.77	19.24	109.29	4.00	4,673.91	76.98	0.00
Ult	51.89	25.95

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	1.00	18.51	9.96	50.00	0.00	0.00	0.79	0.00	319.08	93.27
2027	1.00	86.81	46.70	0.00	0.00	0.00	3.73	0.00	1,730.78	573.09
2028	1.00	56.56	30.43	0.00	0.00	0.00	2.43	0.00	1,127.80	856.09
Rem.		58.89	31.68	0.00	0.00	0.00	2.53	0.00	1,174.19	257.47
Total		220.77	118.77	50.00	0.00	0.00	9.48	0.00	4,351.86	1,113.57

Major Phase :	Oil			Abandonment Date :	12/1/2030
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	2,250.00	bbl/month		Revenue Int :	0.82416700	PW	5.00% :	2,195.15
Abandonment :	387.22	bbl/month		Disc. Initial Invest. (M$) :	14.76	PW	10.00% :	1,113.57
Initial Decline :	35.00	% year	b = 0.000	ROInvestment (disc/undisc) :	76.47 / 88.04	PW	15.00% :	568.02
Beg Ratio :	0.500			Years to Payout :	12.28	PW	20.00% :	291.30
End Ratio :	0.500			Internal ROR (%) :	200.00	PW	25.00% :	150.16
						PW	30.00% :	77.80

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

51

Date :    08/21/2014 11:45:32AM			ECONOMIC PROJECTION		Case	:	ST 247 198 (190463) F 9 - GBE
			As Of Date :	07/31/2014	Reserve Cat.	:	Proved Behind Pipe
Project Name :	HYDROCARB ENERGY 06/30/2014		Discount Rate (%) :	10.00	Field	:	RED FISH REEF
Partner :	All Cases		All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Case Type :	RECOMPLETION CASE				Reservoir	:	FB A FRIO 9
Archive Set :	RED.07.14		SEC REPORT		Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :		0.00
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	2.10	103.87	1.73	77.04	109.29	4.00	188.93	308.18	0.00
2018	3.75	186.03	3.09	137.99	109.29	4.00	338.04	551.95	0.00
2019	2.48	123.19	2.05	91.37	109.29	4.00	223.52	365.49	0.00
2020	1.64	81.75	1.36	60.64	109.29	4.00	148.13	242.56	0.00
2021	1.08	53.95	0.89	40.02	109.29	4.00	97.62	160.08	0.00
2022	0.72	35.73	0.59	26.50	109.29	4.00	64.55	106.00	0.00
2023	0.47	23.66	0.39	17.55	109.29	4.00	42.68	70.19	0.00
2024	0.31	15.70	0.26	11.65	109.29	4.00	28.28	46.58	0.00
2025	0.21	10.36	0.17	7.69	109.29	4.00	18.64	30.74	0.00
2026	0.11	5.77	0.09	4.28	109.29	4.00	10.36	17.11	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	12.89	640.00	10.62	474.72	109.29	4.00	1,160.75	1,898.88	0.00
Ult	12.89	640.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	1.00	31.80	12.43	50.00	0.00	0.00	37.96	0.00	364.92	264.40
2018	1.00	56.95	22.25	0.00	0.00	0.00	67.98	0.00	742.82	768.91
2019	1.00	37.69	14.73	0.00	0.00	0.00	45.02	0.00	491.58	1,071.16
2020	1.00	25.01	9.77	0.00	0.00	0.00	29.87	0.00	326.03	1,252.61
2021	1.00	16.50	6.44	0.00	0.00	0.00	19.72	0.00	215.04	1,360.94
2022	1.00	10.92	4.26	0.00	0.00	0.00	13.06	0.00	142.31	1,425.84
2023	1.00	7.23	2.82	0.00	0.00	0.00	8.65	0.00	94.18	1,464.72
2024	1.00	4.79	1.87	0.00	0.00	0.00	5.74	0.00	62.46	1,488.06
2025	1.00	3.16	1.23	0.00	0.00	0.00	3.79	0.00	41.20	1,501.99
2026	0.00	1.76	0.69	0.00	0.00	0.00	2.11	0.00	22.91	1,509.06
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		195.81	76.49	50.00	0.00	0.00	233.88	0.00	2,503.45	1,509.06

Major Phase :	Gas			Abandonment Date :	10/22/2026
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	22,500.00	Mcf/month		Revenue Int :	0.82416700	PW	5.00% :	1,934.41
Abandonment :	500.00	Mcf/month		Disc. Initial Invest. (M$) :	37.07	PW	10.00% :	1,509.06
Initial Decline :	33.80	% year	b = 0.000	ROInvestment (disc/undisc) :	41.70 / 51.07	PW	15.00% :	1,187.25
Beg Ratio :	0.020			Years to Payout :	3.05	PW	20.00% :	941.09
End Ratio :	0.020			Internal ROR (%) :	700.00	PW	25.00% :	750.95
						PW	30.00% :	602.80

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

52

Date :    08/21/2014 11:45:32AM			ECONOMIC PROJECTION		Case	:	ST 247 21 (BP01) - GBE
			As Of Date :	07/31/2014	Reserve Cat.	:	Proved Behind Pipe
Project Name :	HYDROCARB ENERGY 06/30/2014		Discount Rate (%) :	10.00	Field	:	RED FISH REEF
Partner :	All Cases		All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Case Type :	LEASE CASE				Reservoir	:	FRIO 1 & 1B
Archive Set :	RED.07.14		SEC REPORT		Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :		0.00
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	133.41	0.00	95.36	0.00	4.00	0.00	381.43	0.00
2017	0.00	234.07	0.00	167.30	0.00	4.00	0.00	669.20	0.00
2018	0.00	149.19	0.00	106.64	0.00	4.00	0.00	426.55	0.00
2019	0.00	90.27	0.00	64.52	0.00	4.00	0.00	258.08	0.00
2020	0.00	54.73	0.00	39.12	0.00	4.00	0.00	156.48	0.00
2021	0.00	33.00	0.00	23.59	0.00	4.00	0.00	94.35	0.00
2022	0.00	19.97	0.00	14.27	0.00	4.00	0.00	57.09	0.00
2023	0.00	12.08	0.00	8.64	0.00	4.00	0.00	34.54	0.00
2024	0.00	7.33	0.00	5.24	0.00	4.00	0.00	20.94	0.00
2025	0.00	4.42	0.00	3.16	0.00	4.00	0.00	12.63	0.00
2026	0.00	1.99	0.00	1.42	0.00	4.00	0.00	5.70	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	740.47	0.00	529.25	0.00	4.00	0.00	2,116.99	0.00
Ult	0.00	740.47

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.00	28.61	9.54	250.00	0.00	0.00	49.12	0.00	44.17	30.52
2017	1.00	50.19	16.73	0.00	0.00	0.00	86.18	0.00	516.10	417.36
2018	1.00	31.99	10.66	0.00	0.00	0.00	54.93	0.00	328.96	640.95
2019	1.00	19.36	6.45	0.00	0.00	0.00	33.24	0.00	199.04	763.42
2020	1.00	11.74	3.91	0.00	0.00	0.00	20.15	0.00	120.68	830.63
2021	1.00	7.08	2.36	0.00	0.00	0.00	12.15	0.00	72.76	867.32
2022	1.00	4.28	1.43	0.00	0.00	0.00	7.35	0.00	44.03	887.41
2023	1.00	2.59	0.86	0.00	0.00	0.00	4.45	0.00	26.64	898.41
2024	1.00	1.57	0.52	0.00	0.00	0.00	2.70	0.00	16.15	904.45
2025	1.00	0.95	0.32	0.00	0.00	0.00	1.63	0.00	9.74	907.75
2026	1.00	0.43	0.14	0.00	0.00	0.00	0.73	0.00	4.39	909.11
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		158.77	52.92	250.00	0.00	0.00	272.63	0.00	1,382.66	909.11

Major Phase :	Gas			Abandonment Date :	9/10/2026
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	22,660.42	Mcf/month		Revenue Int :	0.79416670	PW	5.00% :	1,116.98
Abandonment :	200.00	Mcf/month		Disc. Initial Invest. (M$) :	206.51	PW	10.00% :	909.11
Initial Decline :	10.00	% year	b = 0.000	ROInvestment (disc/undisc) :	5.40 / 6.53	PW	15.00% :	744.76
Beg Ratio :	0.000			Years to Payout :	2.35	PW	20.00% :	613.59
End Ratio :	0.000			Internal ROR (%) :	247.82	PW	25.00% :	508.04
						PW	30.00% :	422.47

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

53

Date :    08/21/2014 11:45:32AM			ECONOMIC SUMMARY PROJECTION
			As Of Date :	07/31/2014	Proved Behind Pipe Rsv Class & Category
Project Name :	HYDROCARB ENERGY 06/30/2014		Discount Rate (%) :	10.00	TRINITY BAY Field
Partner :	All Cases		All Cases
Case Type :	REPORT BREAK TOTAL CASE
			SEC REPORT
Cum Oil (Mbbl) :		0.00
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.73	86.65	1.41	0.00	109.28	0.00	153.86	0.00	0.00
2016	2.65	132.39	2.15	72.16	109.28	4.55	235.07	328.38	0.00
2017	1.37	68.52	1.11	37.97	109.28	4.55	121.68	172.81	0.00
2018	0.71	35.62	0.58	20.06	109.28	4.55	63.25	91.28	0.00
2019	0.34	17.10	0.28	10.59	109.28	4.55	30.36	48.21	0.00
2020	0.14	6.90	0.11	5.61	109.28	4.55	12.25	25.52	0.00
2021	0.07	3.63	0.06	2.95	109.28	4.55	6.45	13.43	0.00
2022	0.04	1.92	0.03	1.56	109.28	4.55	3.41	7.09	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	7.05	352.73	5.73	150.90	109.28	4.55	626.33	686.72	0.00
Ult	7.05	352.73

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	7.08	3.85	300.00	0.00	0.00	0.00	0.00	-157.07	-152.06
2016	2.00	35.44	14.09	0.00	0.00	0.00	0.00	0.00	513.93	274.73
2017	2.00	18.56	7.36	0.00	0.00	0.00	0.00	0.00	268.57	476.60
2018	2.00	9.76	3.86	0.00	0.00	0.00	0.00	0.00	140.91	572.49
2019	2.00	5.01	1.96	0.00	0.00	0.00	0.00	0.00	71.60	616.65
2020	1.00	2.48	0.94	0.00	0.00	0.00	0.00	0.00	34.35	635.80
2021	1.00	1.30	0.50	0.00	0.00	0.00	0.00	0.00	18.08	644.93
2022	1.00	0.69	0.26	0.00	0.00	0.00	0.00	0.00	9.55	649.29
2023	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	649.29
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		80.32	32.83	300.00	0.00	0.00	0.00	0.00	899.91	649.29

		Present Worth Profile (M$)
		PW	5.00% :	763.71
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	649.29
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	552.59
Years to Payout :	0.00	PW	20.00% :	470.43
Internal ROR (%) :	0.00	PW	25.00% :	400.27
		PW	30.00% :	340.09

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

54

Date :    08/21/2014 11:45:32AM			ECONOMIC PROJECTION		Case	:	TBSU #1 053 - GBE
			As Of Date :	07/31/2014	Reserve Cat.	:	Proved Behind Pipe
Project Name :	HYDROCARB ENERGY 06/30/2014		Discount Rate (%) :	10.00	Field	:	TRINITY BAY
Partner :	All Cases		All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Case Type :	LEASE CASE				Reservoir	:	FRIO 3
Archive Set :	RED.07.14		SEC REPORT		Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :		0.00
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.73	86.65	1.41	0.00	109.28	0.00	153.86	0.00	0.00
2016	0.87	43.57	0.71	0.00	109.28	0.00	77.37	0.00	0.00
2017	0.44	21.79	0.35	0.00	109.28	0.00	38.68	0.00	0.00
2018	0.22	10.93	0.18	0.00	109.28	0.00	19.42	0.00	0.00
2019	0.08	4.06	0.07	0.00	109.28	0.00	7.21	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	3.34	167.00	2.71	0.00	109.28	0.00	296.54	0.00	0.00
Ult	3.34	167.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	7.08	3.85	250.00	0.00	0.00	0.00	0.00	-107.07	-108.54
2016	1.00	3.56	1.93	0.00	0.00	0.00	0.00	0.00	71.88	-48.83
2017	1.00	1.78	0.97	0.00	0.00	0.00	0.00	0.00	35.94	-21.80
2018	1.00	0.89	0.49	0.00	0.00	0.00	0.00	0.00	18.04	-9.53
2019	1.00	0.33	0.18	0.00	0.00	0.00	0.00	0.00	6.70	-5.34
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		13.64	7.41	250.00	0.00	0.00	0.00	0.00	25.48	-5.34

Major Phase :	Gas			Abandonment Date :	8/31/2019
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	10,000.00	Mcf/month		Revenue Int :	0.81243864	PW	5.00% :	8.92
Abandonment :	400.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-5.34
Initial Decline :	49.83	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-17.64
Beg Ratio :	0.020			Years to Payout :	0.00	PW	20.00% :	-28.25
End Ratio :	0.020			Internal ROR (%) :	0.00	PW	25.00% :	-37.41
						PW	30.00% :	-45.33

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

55

Date :      08/21/2014 11:45:32 AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	TBSU #1 135 - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Behind Pipe
Case Type :	LEASE CASE	All Cases		Field	:	TRINITY BAY
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	FRIO F 5
Cum Oil (Mbbl) :	0.00			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.78	88.81	1.44	72.16	109.28	4.55	157.70	328.38	0.00
2017	0.93	46.74	0.76	37.97	109.28	4.55	82.99	172.81	0.00
2018	0.49	24.69	0.40	20.06	109.28	4.55	43.84	91.28	0.00
2019	0.26	13.04	0.21	10.59	109.28	4.55	23.15	48.21	0.00
2020	0.14	6.90	0.11	5.61	109.28	4.55	12.25	25.52	0.00
2021	0.07	3.63	0.06	2.95	109.28	4.55	6.45	13.43	0.00
2022	0.04	1.92	0.03	1.56	109.28	4.55	3.41	7.09	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	3.71	185.73	3.02	150.90	109.28	4.55	329.80	686.72	0.00
Ult	3.71	185.73

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	50.00	0.00	0.00	0.00	0.00	-50.00	-43.52
2016	1.00	31.88	12.15	0.00	0.00	0.00	0.00	0.00	442.05	323.56
2017	1.00	16.78	6.40	0.00	0.00	0.00	0.00	0.00	232.63	498.41
2018	1.00	8.86	3.38	0.00	0.00	0.00	0.00	0.00	122.88	582.02
2019	1.00	4.68	1.78	0.00	0.00	0.00	0.00	0.00	64.90	622.00
2020	1.00	2.48	0.94	0.00	0.00	0.00	0.00	0.00	34.35	641.15
2021	1.00	1.30	0.50	0.00	0.00	0.00	0.00	0.00	18.08	650.27
2022	1.00	0.69	0.26	0.00	0.00	0.00	0.00	0.00	9.55	654.63
2023	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	654.63
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		66.67	25.41	50.00	0.00	0.00	0.00	0.00	874.43	654.63

Major Phase :	Gas			Abandonment Date :	1/1/2023
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	10,000.00	Mcf/month		Revenue Int :	0.81243864	PW	5.00% :	754.79
Abandonment :	114.11	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	654.63
Initial Decline :	47.20	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	570.23
Beg Ratio :	0.020			Years to Payout :	0.00	PW	20.00% :	498.68
End Ratio :	0.020			Internal ROR (%) :	0.00	PW	25.00% :	437.68
						PW	30.00% :	385.41

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

56

This Page Is Intentionally Left Blank

Proved UndevelopedEconomic Detailed Report

Date :      08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014
Partner :	All Cases	Discount Rate (%) :	10.00	Proved Undeveloped Rsv Class & Category
Case Type :	REPORT BREAK TOTAL CASE	All Cases		RED FISH REEF Field
Cum Oil (Mbbl) :	0.00	SEC REPORT
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	12.52	368.19	9.94	263.16	109.29	4.00	1,086.53	1,052.65	0.00
2016	26.44	787.05	21.00	562.54	109.29	4.00	2,295.06	2,250.18	0.00
2017	21.97	694.65	17.46	497.61	109.29	4.00	1,908.51	1,990.44	0.00
2018	27.26	1,347.68	21.72	968.67	109.29	4.00	2,373.44	3,874.69	0.00
2019	19.09	943.60	15.21	678.24	109.29	4.00	1,661.81	2,712.94	0.00
2020	13.40	662.19	10.67	475.96	109.29	4.00	1,166.21	1,903.85	0.00
2021	9.35	462.14	7.45	332.17	109.29	4.00	813.89	1,328.69	0.00
2022	6.55	323.58	5.21	232.58	109.29	4.00	569.86	930.31	0.00
2023	4.58	226.56	3.65	162.84	109.29	4.00	399.00	651.38	0.00
2024	3.22	158.99	2.56	114.28	109.29	4.00	280.01	457.12	0.00
2025	9.12	313.06	7.25	224.20	109.29	4.00	791.81	896.82	0.00
2026	7.51	252.47	5.97	180.77	109.29	4.00	652.60	723.06	0.00
2027	13.67	503.79	10.89	363.34	109.29	4.00	1,190.63	1,453.35	0.00
2028	24.03	806.64	19.14	581.37	109.29	4.00	2,091.41	2,325.46	0.00
Rem	20.08	743.93	16.01	537.28	109.29	4.00	1,749.34	2,149.10	0.00
Total	218.79	8,594.52	174.12	6,175.01	109.29	4.00	19,030.10	24,700.05	0.00
Ult	218.79	8,594.52

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	128.93	53.48	2,500.00	0.00	0.00	135.56	0.00	-678.79	-730.23
2016	2.00	274.34	113.63	3,200.00	0.00	0.00	289.78	0.00	667.49	-278.32
2017	3.00	237.07	97.47	2,500.00	0.00	0.00	256.04	0.00	808.36	388.73
2018	4.00	399.78	156.20	3,200.00	0.00	0.00	497.55	0.00	1,994.59	1,639.40
2019	4.00	279.91	109.37	0.00	0.00	0.00	348.37	0.00	3,637.10	3,874.65
2020	4.00	196.43	76.75	0.00	0.00	0.00	244.48	0.00	2,552.40	5,294.49
2021	4.00	137.09	53.56	0.00	0.00	0.00	170.62	0.00	1,781.31	6,191.41
2022	4.00	95.99	37.50	0.00	0.00	0.00	119.46	0.00	1,247.22	6,759.92
2023	4.00	67.21	26.26	0.00	0.00	0.00	83.64	0.00	873.27	7,120.26
2024	4.00	47.16	18.43	0.00	0.00	0.00	58.70	0.00	612.83	7,349.16
2025	5.00	103.68	42.22	350.00	0.00	0.00	115.38	0.00	1,077.35	7,706.62
2026	4.00	84.25	34.39	0.00	0.00	0.00	93.03	0.00	1,163.99	8,062.86
2027	6.00	163.77	66.10	700.00	0.00	0.00	186.30	0.00	1,527.81	8,475.38
2028	4.00	270.61	110.42	0.00	0.00	0.00	298.20	0.00	3,737.64	9,414.39
Rem.		241.65	97.46	0.00	0.00	0.00	275.29	0.00	3,284.03	722.34
Total		2,727.89	1,093.25	12,450.00	0.00	0.00	3,172.42	0.00	24,286.60	10,136.73

		Present Worth Profile (M$)
		PW	5.00% :	15,415.22
Disc. Initial Invest. (M$) :	312.98	PW	10.00% :	10,136.73
ROInvestment (disc/undisc) :	33.39 / 24.13	PW	15.00% :	6,852.21
Years to Payout :	2.73	PW	20.00% :	4,716.47
Internal ROR (%) :	55.30	PW	25.00% :	3,270.01
		PW	30.00% :	2,254.79

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

57

Date :      08/21/2014 11:45:32 AM
		ECONOMIC PROJECTION
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Case	:	ST 224 ACW #15L - GBE
Partner :	All Cases	Discount Rate (%) :	10.00	Reserve Cat.	:	Proved Undeveloped
Case Type :	LEASE CASE	All Cases		Field	:	RED FISH REEF
Archive Set :	RED.07.14			Operator	:	GALVESTON BAY ENERGY LLC
		SEC REPORT		Reservoir	:	FRIO 4
Cum Oil (Mbbl) :	0.00			Co., State	:	CHAMBERS, TX
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.64	59.18	0.52	43.41	109.29	4.00	56.93	173.63	0.00
2018	3.12	289.08	2.54	212.04	109.29	4.00	278.09	848.17	0.00
2019	2.19	202.41	1.78	148.47	109.29	4.00	194.71	593.87	0.00
2020	1.53	142.04	1.25	104.19	109.29	4.00	136.64	416.76	0.00
2021	1.07	99.13	0.87	72.71	109.29	4.00	95.36	290.85	0.00
2022	0.75	69.41	0.61	50.91	109.29	4.00	66.77	203.65	0.00
2023	0.52	48.60	0.43	35.65	109.29	4.00	46.75	142.59	0.00
2024	0.37	34.10	0.30	25.02	109.29	4.00	32.81	100.06	0.00
2025	0.26	23.80	0.21	17.46	109.29	4.00	22.90	69.83	0.00
2026	0.18	16.67	0.15	12.22	109.29	4.00	16.03	48.90	0.00
2027	0.06	5.27	0.05	3.87	109.29	4.00	5.07	15.47	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	10.69	989.70	8.71	725.94	109.29	4.00	952.06	2,903.77	0.00
Ult	10.69	989.70

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	1.00	15.64	5.76	2,500.00	0.00	0.00	22.07	0.00	-2,312.91	-1,673.63
2018	1.00	76.41	28.16	0.00	0.00	0.00	107.79	0.00	913.91	-1,053.20
2019	1.00	53.50	19.71	0.00	0.00	0.00	75.47	0.00	639.89	-659.94
2020	1.00	37.54	13.83	0.00	0.00	0.00	52.96	0.00	449.06	-410.14
2021	1.00	26.20	9.66	0.00	0.00	0.00	36.96	0.00	313.39	-252.34
2022	1.00	18.34	6.76	0.00	0.00	0.00	25.88	0.00	219.43	-152.32
2023	1.00	12.84	4.73	0.00	0.00	0.00	18.12	0.00	153.64	-88.93
2024	1.00	9.01	3.32	0.00	0.00	0.00	12.72	0.00	107.82	-48.66
2025	1.00	6.29	2.32	0.00	0.00	0.00	8.87	0.00	75.25	-23.22
2026	1.00	4.40	1.62	0.00	0.00	0.00	6.21	0.00	52.69	-7.09
2027	1.00	1.39	0.51	0.00	0.00	0.00	1.97	0.00	16.67	-2.35
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		261.58	96.40	2,500.00	0.00	0.00	369.03	0.00	628.82	-2.35

Major Phase :	Gas			Abandonment Date :	5/29/2027
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	30,416.67	Mcf/month		Revenue Int :	0.81500000	PW	5.00% :	238.14
Abandonment :	1,000.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-2.35
Initial Decline :	30.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-145.73
Beg Ratio :	0.011			Years to Payout :	0.00	PW	20.00% :	-226.32
End Ratio :	0.011			Internal ROR (%) :	0.00	PW	25.00% :	-266.47
						PW	30.00% :	-280.85

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

58

Date :	08/21/2014 11:45:32AM		ECONOMIC PROJECTION
						Case	:	ST 224 ACW #15U - GBE
Project Name :		HYDROCARB ENERGY 06/30/2014		As Of Date :	07/31/2014	Reserve Cat.	:	Proved Undeveloped
Partner :		All Cases		Discount Rate (%) :	10.00	Field	:	RED FISH REEF
Case Type :		RECOMPLETION CASE		All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :		RED.07.14				Reservoir	:	FRIO 1
				SEC REPORT		Co., State	:	CHAMBERS, TX

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	1.68	168.30	1.37	123.45	109.29	4.00	149.91	493.80	0.00
2028	2.57	256.95	2.09	188.47	109.29	4.00	228.87	753.89	0.00
Rem	2.96	296.17	2.41	217.24	109.29	4.00	263.80	868.95	0.00
Total	7.21	721.42	5.88	529.16	109.29	4.00	642.58	2,116.64	0.00
Ult	7.21	721.42

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	1.00	43.93	16.09	350.00	0.00	0.00	62.76	0.00	170.93	43.76
2028	1.00	67.07	24.57	0.00	0.00	0.00	95.81	0.00	795.31	243.21
Rem.		77.31	28.32	0.00	0.00	0.00	110.43	0.00	916.69	200.57
Total		188.31	68.98	350.00	0.00	0.00	269.00	0.00	1,882.93	443.78

Major Phase :	Gas			Abandonment Date :	12/1/2030
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	30,416.67	Mcf/month		Revenue Int :	0.81500000	PW	5.00% :	912.03
Abandonment :	8,974.05	Mcf/month		Disc. Initial Invest. (M$) :	96.70	PW	10.00% :	443.78
Initial Decline :	30.00	% year	b = 0.000	ROInvestment (disc/undisc) :	5.59 / 6.38	PW	15.00% :	216.91
Beg Ratio :	0.010			Years to Payout :	13.25	PW	20.00% :	106.49
End Ratio :	0.010			Internal ROR (%) :	150.00	PW	25.00% :	52.50
						PW	30.00% :	26.00

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

59

Date :	08/21/2014 11:45:32AM		ECONOMIC PROJECTION
					Case	:	ST 246 ACW #35L - GBE
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Reserve Cat.	:	Proved Undeveloped
Partner :		All Cases	Discount Rate (%) :	10.00	Field	:	RED FISH REEF
Case Type :		LEASE CASE	All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :		RED.07.14			Reservoir	:	FRIO 10B
			SEC REPORT		Co., State	:	CHAMBERS, TX

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	12.52	368.19	9.94	263.16	109.29	4.00	1,086.53	1,052.65	0.00
2016	8.79	258.39	6.98	184.68	109.29	4.00	762.49	738.72	0.00
2017	6.13	180.33	4.87	128.89	109.29	4.00	532.14	515.55	0.00
2018	4.29	126.26	3.41	90.24	109.29	4.00	372.59	360.97	0.00
2019	3.01	88.40	2.39	63.19	109.29	4.00	260.88	252.74	0.00
2020	2.11	62.04	1.68	44.34	109.29	4.00	183.07	177.37	0.00
2021	1.47	43.30	1.17	30.95	109.29	4.00	127.77	123.78	0.00
2022	1.03	30.31	0.82	21.67	109.29	4.00	89.46	86.67	0.00
2023	0.72	21.23	0.57	15.17	109.29	4.00	62.64	60.68	0.00
2024	0.51	14.90	0.40	10.65	109.29	4.00	43.96	42.59	0.00
2025	0.03	1.03	0.03	0.73	109.29	4.00	3.03	2.94	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	40.61	1,194.36	32.25	853.67	109.29	4.00	3,524.56	3,414.66	0.00
Ult	40.61	1,194.36

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	128.93	53.48	2,500.00	0.00	0.00	135.56	0.00	-678.79	-730.23
2016	1.00	90.48	37.53	0.00	0.00	0.00	95.13	0.00	1,278.07	328.65
2017	1.00	63.14	26.19	0.00	0.00	0.00	66.39	0.00	891.96	997.54
2018	1.00	44.21	18.34	0.00	0.00	0.00	46.49	0.00	624.52	1,421.52
2019	1.00	30.96	12.84	0.00	0.00	0.00	32.55	0.00	437.27	1,690.25
2020	1.00	21.72	9.01	0.00	0.00	0.00	22.84	0.00	306.86	1,860.95
2021	1.00	15.16	6.29	0.00	0.00	0.00	15.94	0.00	214.16	1,968.78
2022	1.00	10.62	4.40	0.00	0.00	0.00	11.16	0.00	149.95	2,037.13
2023	1.00	7.43	3.08	0.00	0.00	0.00	7.81	0.00	104.99	2,080.46
2024	1.00	5.22	2.16	0.00	0.00	0.00	5.48	0.00	73.68	2,107.98
2025	1.00	0.36	0.15	0.00	0.00	0.00	0.38	0.00	5.08	2,109.77
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		418.23	173.48	2,500.00	0.00	0.00	439.75	0.00	3,407.76	2,109.77

Major Phase :	Gas			Abandonment Date :	1/30/2025
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	36,500.00	Mcf/month		Revenue Int :	0.79416000	PW	5.00% :	2,683.14
Abandonment :	1,000.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	2,109.77
Initial Decline :	30.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	1,649.96
Beg Ratio :	0.034			Years to Payout :	0.00	PW	20.00% :	1,276.74
End Ratio :	0.034			Internal ROR (%) :	0.00	PW	25.00% :	970.48
						PW	30.00% :	716.76

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

60

Date :	08/21/2014 11:45:32AM		ECONOMIC PROJECTION
					Case	:	ST 246 ACW #35U - GBE
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Reserve Cat.	:	Proved Undeveloped
Partner :		All Cases	Discount Rate (%) :	10.00	Field	:	RED FISH REEF
Case Type :		RECOMPLETION CASE	All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :		RED.07.14			Reservoir	:	FRIO 10A
			SEC REPORT		Co., State	:	CHAMBERS, TX

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	7.19	211.47	5.71	151.15	109.29	4.00	624.04	604.58	0.00
2026	6.19	182.06	4.92	130.13	109.29	4.00	537.26	520.50	0.00
2027	4.33	127.47	3.44	91.11	109.29	4.00	376.17	364.44	0.00
2028	3.04	89.46	2.42	63.94	109.29	4.00	263.98	255.75	0.00
Rem	3.51	103.11	2.78	73.70	109.29	4.00	304.27	294.79	0.00
Total	24.26	713.56	19.27	510.02	109.29	4.00	2,105.72	2,040.07	0.00
Ult	24.26	713.56

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	1.00	74.05	30.72	350.00	0.00	0.00	77.86	0.00	696.00	228.46
2026	1.00	63.75	26.44	0.00	0.00	0.00	67.03	0.00	900.53	504.07
2027	1.00	44.64	18.52	0.00	0.00	0.00	46.93	0.00	630.53	678.77
2028	1.00	31.32	12.99	0.00	0.00	0.00	32.94	0.00	442.48	789.73
Rem.		36.11	14.98	0.00	0.00	0.00	37.96	0.00	510.01	111.59
Total		249.87	103.64	350.00	0.00	0.00	262.72	0.00	3,179.56	901.33

Major Phase :	Gas			Abandonment Date :	12/1/2030
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	24,333.33	Mcf/month		Revenue Int :	0.79416700	PW	5.00% :	1,686.61
Abandonment :	3,124.26	Mcf/month		Disc. Initial Invest. (M$) :	121.98	PW	10.00% :	901.33
Initial Decline :	30.00	% year	b = 0.000	ROInvestment (disc/undisc) :	8.39 / 10.08	PW	15.00% :	485.08
Beg Ratio :	0.034			Years to Payout :	10.84	PW	20.00% :	262.82
End Ratio :	0.034			Internal ROR (%) :	200.00	PW	25.00% :	143.31
						PW	30.00% :	78.61

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

61

Date :	08/21/2014 11:45:32AM		ECONOMIC PROJECTION
					Case	:	ST 246 ACW #40L - GBE
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Reserve Cat.	:	Proved Undeveloped
Partner :		All Cases	Discount Rate (%) :	10.00	Field	:	RED FISH REEF
Case Type :		LEASE CASE	All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :		RED.07.14			Reservoir	:	FRIO 17
			SEC REPORT		Co., State	:	CHAMBERS, TX

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	17.66	528.67	14.02	377.86	109.29	4.00	1,532.57	1,511.46	0.00
2017	15.20	455.15	12.07	325.32	109.29	4.00	1,319.44	1,301.26	0.00
2018	10.64	318.68	8.45	227.78	109.29	4.00	923.83	911.10	0.00
2019	7.45	223.13	5.92	159.48	109.29	4.00	646.84	637.93	0.00
2020	5.23	156.59	4.15	111.92	109.29	4.00	453.93	447.68	0.00
2021	3.65	109.28	2.90	78.11	109.29	4.00	316.80	312.43	0.00
2022	2.56	76.51	2.03	54.69	109.29	4.00	221.81	218.76	0.00
2023	1.79	53.57	1.42	38.29	109.29	4.00	155.31	153.17	0.00
2024	1.26	37.60	1.00	26.87	109.29	4.00	108.99	107.49	0.00
2025	0.88	26.24	0.70	18.75	109.29	4.00	76.06	75.02	0.00
2026	0.61	18.37	0.49	13.13	109.29	4.00	53.26	52.52	0.00
2027	0.31	9.26	0.25	6.62	109.29	4.00	26.84	26.47	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	67.24	2,013.04	53.40	1,438.82	109.29	4.00	5,835.67	5,755.28	0.00
Ult	67.24	2,013.04

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.00	183.86	76.10	3,200.00	0.00	0.00	194.65	0.00	-610.58	-606.97
2017	1.00	158.29	65.52	0.00	0.00	0.00	167.58	0.00	2,229.31	1,064.82
2018	1.00	110.83	45.87	0.00	0.00	0.00	117.33	0.00	1,560.90	2,124.48
2019	1.00	77.60	32.12	0.00	0.00	0.00	82.15	0.00	1,092.90	2,796.14
2020	1.00	54.46	22.54	0.00	0.00	0.00	57.65	0.00	766.96	3,222.78
2021	1.00	38.01	15.73	0.00	0.00	0.00	40.24	0.00	535.26	3,492.29
2022	1.00	26.61	11.01	0.00	0.00	0.00	28.17	0.00	374.77	3,663.12
2023	1.00	18.63	7.71	0.00	0.00	0.00	19.73	0.00	262.40	3,771.40
2024	1.00	13.08	5.41	0.00	0.00	0.00	13.84	0.00	184.15	3,840.18
2025	1.00	9.13	3.78	0.00	0.00	0.00	9.66	0.00	128.52	3,883.62
2026	1.00	6.39	2.64	0.00	0.00	0.00	6.76	0.00	89.98	3,911.16
2027	1.00	3.22	1.33	0.00	0.00	0.00	3.41	0.00	45.34	3,923.90
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		700.09	289.77	3,200.00	0.00	0.00	741.18	0.00	6,659.91	3,923.90

Major Phase :	Gas			Abandonment Date :	9/5/2027
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	60,833.33	Mcf/month		Revenue Int :	0.79416700	PW	5.00% :	5,093.37
Abandonment :	1,000.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	3,923.90
Initial Decline :	30.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	3,038.04
Beg Ratio :	0.033			Years to Payout :	0.00	PW	20.00% :	2,358.54
End Ratio :	0.033			Internal ROR (%) :	0.00	PW	25.00% :	1,831.75
						PW	30.00% :	1,419.73

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

62

Date :	08/21/2014 11:45:32AM		ECONOMIC PROJECTION
					Case	:	ST 246 ACW #40U - GBE
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Reserve Cat.	:	Proved Undeveloped
Partner :		All Cases	Discount Rate (%) :	10.00	Field	:	RED FISH REEF
Case Type :		RECOMPLETION CASE	All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :		RED.07.14			Reservoir	:	FRIO 15B
			SEC REPORT		Co., State	:	CHAMBERS, TX

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	6.92	168.72	5.49	120.59	109.29	4.00	600.39	482.36	0.00
2028	18.16	442.85	14.42	316.53	109.29	4.00	1,575.93	1,266.12	0.00
Rem	13.31	324.62	10.57	232.02	109.29	4.00	1,155.18	928.08	0.00
Total	38.38	936.19	30.48	669.14	109.29	4.00	3,331.50	2,676.57	0.00
Ult	38.38	936.19

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	1.00	63.80	27.07	350.00	0.00	0.00	62.12	0.00	579.77	153.15
2028	1.00	167.45	71.05	0.00	0.00	0.00	163.05	0.00	2,440.49	766.86
Rem.		122.74	52.08	0.00	0.00	0.00	119.52	0.00	1,788.92	395.20
Total		353.99	150.20	350.00	0.00	0.00	344.69	0.00	4,809.18	1,162.06

Major Phase :	Gas			Abandonment Date :	12/1/2030
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	60,833.33	Mcf/month		Revenue Int :	0.79416700	PW	5.00% :	2,358.75
Abandonment :	6,756.89	Mcf/month		Disc. Initial Invest. (M$) :	94.30	PW	10.00% :	1,162.06
Initial Decline :	50.00	% year	b = 0.000	ROInvestment (disc/undisc) :	13.32 / 14.74	PW	15.00% :	575.01
Beg Ratio :	0.041			Years to Payout :	13.26	PW	20.00% :	285.75
End Ratio :	0.041			Internal ROR (%) :	200.00	PW	25.00% :	142.60
						PW	30.00% :	71.46

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

63

Date :     08/21/2014 11:45:32AM			ECONOMIC PROJECTION		Case	:	ST 247 119 OFFSET - GBE
			As Of Date :	07/31/2014	Reserve Cat.	:	Proved Undeveloped
Project Name :	HYDROCARB ENERGY 06/30/2014		Discount Rate (%) :	10.00	Field	:	RED FISH REEF
Partner :	All Cases		All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Case Type :	LEASE CASE				Reservoir	:	FRIO 15-B
Archive Set :	RED.07.14		SEC REPORT		Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :		0.00
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	9.20	613.65	7.31	438.61	109.29	4.00	798.93	1,754.44	0.00
2019	6.44	429.66	5.12	307.10	109.29	4.00	559.39	1,228.41	0.00
2020	4.52	301.52	3.59	215.51	109.29	4.00	392.56	862.06	0.00
2021	3.16	210.43	2.51	150.41	109.29	4.00	273.97	601.63	0.00
2022	2.21	147.34	1.76	105.31	109.29	4.00	191.82	421.24	0.00
2023	1.55	103.16	1.23	73.74	109.29	4.00	134.31	294.94	0.00
2024	1.09	72.40	0.86	51.74	109.29	4.00	94.25	206.98	0.00
2025	0.76	50.52	0.60	36.11	109.29	4.00	65.78	144.45	0.00
2026	0.53	35.38	0.42	25.28	109.29	4.00	46.06	101.14	0.00
2027	0.37	24.77	0.30	17.70	109.29	4.00	32.25	70.82	0.00
2028	0.26	17.38	0.21	12.42	109.29	4.00	22.63	49.70	0.00
Rem	0.30	20.04	0.24	14.32	109.29	4.00	26.08	57.28	0.00
Total	30.39	2,026.26	24.14	1,448.27	109.29	4.00	2,638.02	5,793.07	0.00
Ult	30.39	2,026.26

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	1.00	168.33	63.83	3,200.00	0.00	0.00	225.94	0.00	-1,104.74	-853.39
2019	1.00	117.86	44.69	0.00	0.00	0.00	158.20	0.00	1,467.04	48.20
2020	1.00	82.71	31.37	0.00	0.00	0.00	111.02	0.00	1,029.52	620.91
2021	1.00	57.72	21.89	0.00	0.00	0.00	77.48	0.00	718.50	982.68
2022	1.00	40.42	15.33	0.00	0.00	0.00	54.25	0.00	503.07	1,211.99
2023	1.00	28.30	10.73	0.00	0.00	0.00	37.98	0.00	352.24	1,357.34
2024	1.00	19.86	7.53	0.00	0.00	0.00	26.66	0.00	247.19	1,449.66
2025	1.00	13.86	5.26	0.00	0.00	0.00	18.60	0.00	172.51	1,507.98
2026	1.00	9.70	3.68	0.00	0.00	0.00	13.02	0.00	120.79	1,544.95
2027	1.00	6.79	2.58	0.00	0.00	0.00	9.12	0.00	84.57	1,568.38
2028	1.00	4.77	1.81	0.00	0.00	0.00	6.40	0.00	59.35	1,583.27
Rem.		5.50	2.08	0.00	0.00	0.00	7.38	0.00	68.41	14.97
Total		555.83	210.78	3,200.00	0.00	0.00	746.04	0.00	3,718.44	1,598.24

Major Phase :	Gas			Abandonment Date :	12/1/2030
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	60,833.33	Mcf/month		Revenue Int :	0.79416700	PW	5.00% :	2,443.19
Abandonment :	607.08	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	1,598.24
Initial Decline :	30.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	1,032.94
Beg Ratio :	0.015			Years to Payout :	0.00	PW	20.00% :	652.46
End Ratio :	0.015			Internal ROR (%) :	0.00	PW	25.00% :	395.83
						PW	30.00% :	223.08

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

64

Date :     08/21/2014 11:45:32AM			ECONOMIC SUMMARY PROJECTION		Proved Undeveloped Rsv Class & Category
			As Of Date :	07/31/2014		TRINITY BAY Field
Project Name :	HYDROCARB ENERGY 06/30/2014		Discount Rate (%) :	10.00
Partner :	All Cases		All Cases
Case Type :	REPORT BREAK TOTAL CASE
			SEC REPORT
Cum Oil (Mbbl) :		0.00
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	115.80	19.52	94.08	15.86	100.11	4.10	9,418.45	65.02	0.00
2018	94.97	16.01	77.16	13.01	100.11	4.10	7,724.18	53.32	0.00
2019	77.89	13.13	63.28	10.67	100.11	4.10	6,334.69	43.73	0.00
2020	64.03	10.79	52.02	8.77	100.11	4.10	5,208.01	35.95	0.00
2021	52.36	8.83	42.54	7.17	100.11	4.10	4,258.29	29.40	0.00
2022	42.94	7.24	34.88	5.88	100.11	4.10	3,492.27	24.11	0.00
2023	35.21	5.94	28.61	4.82	100.11	4.10	2,864.05	19.77	0.00
2024	28.95	4.88	23.52	3.96	100.11	4.10	2,354.66	16.26	0.00
2025	22.48	3.79	18.26	3.08	100.11	4.10	1,828.15	12.62	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	534.62	90.12	434.35	73.22	100.11	4.10	43,482.74	300.19	0.00
Ult	534.62	90.12

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	1.00	438.13	237.09	2,500.00	0.00	0.00	0.00	0.00	6,308.26	4,632.85
2018	1.00	359.31	194.44	0.00	0.00	0.00	0.00	0.00	7,223.75	9,530.53
2019	1.00	294.68	159.46	0.00	0.00	0.00	0.00	0.00	5,924.28	13,166.70
2020	1.00	242.27	131.10	0.00	0.00	0.00	0.00	0.00	4,870.60	15,872.60
2021	1.00	198.09	107.19	0.00	0.00	0.00	0.00	0.00	3,982.41	17,875.20
2022	1.00	162.45	87.91	0.00	0.00	0.00	0.00	0.00	3,266.02	19,361.99
2023	1.00	133.23	72.10	0.00	0.00	0.00	0.00	0.00	2,678.50	20,465.81
2024	1.00	109.53	59.27	0.00	0.00	0.00	0.00	0.00	2,202.11	21,287.24
2025	1.00	85.04	46.02	0.00	0.00	0.00	0.00	0.00	1,709.71	21,865.98
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		2,022.72	1,094.57	2,500.00	0.00	0.00	0.00	0.00	38,165.64	21,865.98

		Present Worth Profile (M$)
		PW	5.00% :	28,693.70
Disc. Initial Invest. (M$) :	1,964.02	PW	10.00% :	21,865.98
ROInvestment (disc/undisc) :	12.13 / 16.27	PW	15.00% :	16,869.19
Years to Payout :	2.69	PW	20.00% :	13,159.61
Internal ROR (%) :	427.96	PW	25.00% :	10,368.53
		PW	30.00% :	8,242.42

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

65

Date :     08/21/2014 11:45:32AM			ECONOMIC PROJECTION		Case	:	ST 25-A NO 01
			As Of Date :	07/31/2014	Reserve Cat.	:	Proved Undeveloped
Project Name :	HYDROCARB ENERGY 06/30/2014		Discount Rate (%) :	10.00	Field	:	TRINITY BAY
Partner :	All Cases		All Cases		Operator	:
Case Type :	LEASE CASE				Reservoir	:
Archive Set :	RED.07.14		SEC REPORT		Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :		0.00
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	115.80	19.52	94.08	15.86	100.11	4.10	9,418.45	65.02	0.00
2018	94.97	16.01	77.16	13.01	100.11	4.10	7,724.18	53.32	0.00
2019	77.89	13.13	63.28	10.67	100.11	4.10	6,334.69	43.73	0.00
2020	64.03	10.79	52.02	8.77	100.11	4.10	5,208.01	35.95	0.00
2021	52.36	8.83	42.54	7.17	100.11	4.10	4,258.29	29.40	0.00
2022	42.94	7.24	34.88	5.88	100.11	4.10	3,492.27	24.11	0.00
2023	35.21	5.94	28.61	4.82	100.11	4.10	2,864.05	19.77	0.00
2024	28.95	4.88	23.52	3.96	100.11	4.10	2,354.66	16.26	0.00
2025	22.48	3.79	18.26	3.08	100.11	4.10	1,828.15	12.62	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	534.62	90.12	434.35	73.22	100.11	4.10	43,482.74	300.19	0.00
Ult	534.62	90.12

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	1.00	438.13	237.09	2,500.00	0.00	0.00	0.00	0.00	6,308.26	4,632.85
2018	1.00	359.31	194.44	0.00	0.00	0.00	0.00	0.00	7,223.75	9,530.53
2019	1.00	294.68	159.46	0.00	0.00	0.00	0.00	0.00	5,924.28	13,166.70
2020	1.00	242.27	131.10	0.00	0.00	0.00	0.00	0.00	4,870.60	15,872.60
2021	1.00	198.09	107.19	0.00	0.00	0.00	0.00	0.00	3,982.41	17,875.20
2022	1.00	162.45	87.91	0.00	0.00	0.00	0.00	0.00	3,266.02	19,361.99
2023	1.00	133.23	72.10	0.00	0.00	0.00	0.00	0.00	2,678.50	20,465.81
2024	1.00	109.53	59.27	0.00	0.00	0.00	0.00	0.00	2,202.11	21,287.24
2025	1.00	85.04	46.02	0.00	0.00	0.00	0.00	0.00	1,709.71	21,865.98
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		2,022.72	1,094.57	2,500.00	0.00	0.00	0.00	0.00	38,165.64	21,865.98

Major Phase :	Oil			Abandonment Date :	12/11/2025
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	10,645.83	bbl/month		Revenue Int :	0.81243864	PW	5.00% :	28,693.70
Abandonment :	0.00	bbl/month		Disc. Initial Invest. (M$) :	1,964.02	PW	10.00% :	21,865.98
Initial Decline :	18.00	% year	b = 0.000	ROInvestment (disc/undisc) :	12.13 / 16.27	PW	15.00% :	16,869.19
Beg Ratio :	0.169			Years to Payout :	2.69	PW	20.00% :	13,159.61
End Ratio :	0.000			Internal ROR (%) :	427.96	PW	25.00% :	10,368.53
						PW	30.00% :	8,242.42

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

66

Field Expenses

Economic Detailed Report

Date :	08/21/2014 11:45:32AM		ECONOMIC SUMMARY PROJECTION		Field Exper Rsv Class & Category
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	FISHERS REEF Field
Partner :		All Cases	Discount Rate (%) :	10.00
Case Type :		REPORT BREAK TOTAL CASE	All Cases
			SEC REPORT

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2028	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	2.00	0.00	0.00	0.00	418.09	0.00	0.00	0.00	-418.09	-409.40
2015	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-1,319.48
2016	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-2,143.16
2017	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-2,888.79
2018	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-3,563.79
2019	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-4,174.85
2020	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-4,727.89
2021	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-5,228.53
2022	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-5,681.74
2023	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-6,092.03
2024	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-6,463.36
2025	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-6,799.50
2026	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-7,103.81
2027	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-7,379.29
2028	2.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-7,628.61
Rem.		0.00	0.00	890.34	492.13	0.00	0.00	0.00	-1,382.47	-310.70
Total		0.00	0.00	890.34	14,868.04	0.00	0.00	0.00	-15,758.38	-7,939.30

		Present Worth Profile (M$)
		PW	5.00% :	-10,903.70
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-7,939.30
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-6,055.23
Years to Payout :	0.00	PW	20.00% :	-4,807.80
Internal ROR (%) :	0.00	PW	25.00% :	-3,948.04
		PW	30.00% :	-3,332.50

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

67

Date :	08/21/2014 11:45:32AM		ECONOMIC PROJECTION
					Case	:	FIELD ABANDONMENT EXPENSE
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Reserve Cat.	:	Field Expense
Partner :		All Cases	Discount Rate (%) :	10.00	Field	:	FISHERS REEF
Case Type :		LEASE CASE	All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :		RED.07.14			Reservoir	:	OPEX
			SEC REPORT		Co., State	:	CHAMBERS, TX

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2028	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2028	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem.		0.00	0.00	890.34	0.00	0.00	0.00	0.00	-890.34	-196.54
Total		0.00	0.00	890.34	0.00	0.00	0.00	0.00	-890.34	-196.54

Major Phase :	Gas				Abandonment Date :	10/31/2029	Present Worth Profile (M$)
Perfs :	0 - 0				Working Int :	0.95000000
Initial Rate :		0.00	Mcf/month		Revenue Int :	0.78850000	PW	5.00% :	-417.66
Abandonment :		0.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-196.54
Initial Decline :		0.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-92.77
Beg Ratio :		0.000			Years to Payout :	0.00	PW	20.00% :	-43.93
End Ratio :		0.000			Internal ROR (%) :	0.00	PW	25.00% :	-20.86
							PW	30.00% :	-9.94

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

68

Date :	08/21/2014 11:45:32AM		ECONOMIC PROJECTION
					Case	:	FIELD FIXED OPERATING EXPEN
Project Name :		HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	Reserve Cat.	:	Field Expense
Partner :		All Cases	Discount Rate (%) :	10.00	Field	:	FISHERS REEF
Case Type :		LEASE CASE	All Cases		Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :		RED.07.14			Reservoir	:	OPEX
			SEC REPORT		Co., State	:	CHAMBERS, TX

Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2028	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	418.09	0.00	0.00	0.00	-418.09	-409.40
2015	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-1,319.48
2016	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-2,143.16
2017	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-2,888.79
2018	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-3,563.79
2019	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-4,174.85
2020	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-4,727.89
2021	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-5,228.53
2022	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-5,681.74
2023	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-6,092.03
2024	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-6,463.36
2025	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-6,799.50
2026	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-7,103.81
2027	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-7,379.29
2028	1.00	0.00	0.00	0.00	996.99	0.00	0.00	0.00	-996.99	-7,628.61
Rem.		0.00	0.00	0.00	492.13	0.00	0.00	0.00	-492.13	-114.16
Total		0.00	0.00	0.00	14,868.04	0.00	0.00	0.00	-14,868.04	-7,742.77

Major Phase :	Gas			Abandonment Date :	7/1/2029	Present Worth Profile (M$)
Perfs :	0 - 0			Working Int :	0.95000000
Initial Rate :	0.00	Mcf/month		Revenue Int :	0.62250000	PW	5.00% :	-10,486.05
Abandonment :	0.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-7,742.77
Initial Decline :	0.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-5,962.46
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	-4,763.87
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	-3,927.17
						PW	30.00% :	-3,322.56

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

69

Date :     08/21/2014 11:45:32AM
		ECONOMIC SUMMARY PROJECTION		Field Expense Rsv Class & Category
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	POINT BOLIVAR NORTH Field
Partner :	All Cases	Discount Rate (%) :	10.00
Case Type :	REPORT BREAK TOTAL CASE	All Cases
		SEC REPORT
Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	2.00	0.00	0.00	0.00	101.11	0.00	0.00	0.00	-101.11	-99.01
2015	2.00	0.00	0.00	0.00	241.11	0.00	0.00	0.00	-241.11	-319.10
2016	2.00	0.00	0.00	739.88	99.88	0.00	0.00	0.00	-839.77	-1,004.93
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		0.00	0.00	739.88	442.10	0.00	0.00	0.00	-1,181.99	-1,004.93

		Present Worth Profile (M$)
		PW	5.00% :	-1,089.09
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-1,004.93
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-928.63
Years to Payout :	0.00	PW	20.00% :	-859.38
Internal ROR (%) :	0.00	PW	25.00% :	-796.49
		PW	30.00% :	-739.33

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

70

Date : 08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
		As Of Date :	07/31/2014	Case	:	FIELD ABANDONMENT EXPENSE
Project Name :	HYDROCARB ENERGY 06/30/2014	Discount Rate (%) :	10.00	Reserve Cat.	:	Field Expense
Partner :	All Cases	All Cases		Field	:	POINT BOLIVAR NORTH
Case Type :	LEASE CASE			Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :	RED.07.14	SEC REPORT		Reservoir	:	OPEX
				Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.00	0.00	0.00	739.88	0.00	0.00	0.00	0.00	-739.88	-600.92
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		0.00	0.00	739.88	0.00	0.00	0.00	0.00	-739.88	-600.92

Major Phase :	Oil			Abandonment Date :	9/30/2016
Perfs :	0 - 0			Working Int :	0.90833330	Present Worth Profile (M$)
Initial Rate :	0.00	bbl/month		Revenue Int :	0.64491664	PW	5.00% :	-666.65
Abandonment :	0.00	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-600.92
Initial Decline :	0.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-541.90
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	-488.89
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	-441.25
						PW	30.00% :	-398.42

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

71

Date :      08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
		As Of Date :	07/31/2014	Case	:	FIELD FIXED OPERATING EXPEN
Project Name :	HYDROCARB ENERGY 06/30/2014	Discount Rate (%) :	10.00	Reserve Cat.	:	Field Expense
Partner :	All Cases	All Cases		Field	:	POINT BOLIVAR NORTH
Case Type :	LEASE CASE			Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :	RED.07.14	SEC REPORT		Reservoir	:	OPERATING EXPENSE
				Co., State	:	GALVESTON, TX
Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	101.11	0.00	0.00	0.00	-101.11	-99.01
2015	1.00	0.00	0.00	0.00	241.11	0.00	0.00	0.00	-241.11	-319.10
2016	1.00	0.00	0.00	0.00	99.88	0.00	0.00	0.00	-99.88	-404.01
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		0.00	0.00	0.00	442.10	0.00	0.00	0.00	-442.10	-404.01

Major Phase :	Oil			Abandonment Date :	6/1/2016
Perfs :	0 - 0			Working Int :	0.73330000	Present Worth Profile (M$)
Initial Rate :	0.00	bbl/month		Revenue Int :	0.52064300	PW	5.00% :	-422.44
Abandonment :	0.00	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-404.01
Initial Decline :	0.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-386.72
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	-370.49
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	-355.24
						PW	30.00% :	-340.91

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

72

Date :      08/21/2014 11:45:32AM
			ECONOMIC SUMMARY PROJECTION		Field Expense Rsv Class & Category
Project Name :	HYDROCARB ENERGY 06/30/2014		As Of Date :	07/31/2014	RED FISH REEF Field
Partner :	All Cases		Discount Rate (%) :	10.00
Case Type :	REPORT BREAK TOTAL CASE		All Cases
			SEC REPORT
Cum Oil (Mbbl) :		0.00
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2028	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	2.00	0.00	0.00	0.00	315.42	0.00	0.00	0.00	-315.42	-308.86
2015	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-995.46
2016	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-1,616.87
2017	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-2,179.40
2018	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-2,688.64
2019	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-3,149.64
2020	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-3,566.87
2021	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-3,944.57
2022	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-4,286.49
2023	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-4,596.03
2024	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-4,876.17
2025	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-5,129.77
2026	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-5,359.35
2027	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-5,567.18
2028	2.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-5,755.27
Rem.		0.00	0.00	1,658.25	1,443.66	0.00	0.00	0.00	-3,101.91	-630.56
Total		0.00	0.00	1,658.25	12,289.32	0.00	0.00	0.00	-13,947.57	-6,385.83

		Present Worth Profile (M$)
		PW	5.00% :	-9,127.82
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-6,385.83
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-4,742.86
Years to Payout :	0.00	PW	20.00% :	-3,704.35
Internal ROR (%) :	0.00	PW	25.00% :	-3,012.76
		PW	30.00% :	-2,529.37

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

73

Date :      08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
		As Of Date :	07/31/2014	Case	:	FIELD ABANDONMENT EXPENSE
Project Name :	HYDROCARB ENERGY 06/30/2014	Discount Rate (%) :	10.00	Reserve Cat.	:	Field Expense
Partner :	All Cases	All Cases		Field :		RED FISH REEF
Case Type :	LEASE CASE			Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :	RED.07.14	SEC REPORT		Reservoir	:	OPEX
				Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2028	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2028	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem.		0.00	0.00	1,658.25	0.00	0.00	0.00	0.00	-1,658.25	-318.01
Total		0.00	0.00	1,658.25	0.00	0.00	0.00	0.00	-1,658.25	-318.01

Major Phase :	Gas			Abandonment Date :	3/31/2031
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	0.00	Mcf/month		Revenue Int :	0.81000000	PW	5.00% :	-724.94
Abandonment :	0.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-318.01
Initial Decline :	0.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-139.97
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	-61.82
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	-27.39
						PW	30.00% :	-12.18

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

74

Date :      08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
		As Of Date :	07/31/2014	Case	:	FIELD FIXED OPERATING EXPEN
Project Name :	HYDROCARB ENERGY 06/30/2014	Discount Rate (%) :	10.00	Reserve Cat.	:	Field Expense
Partner :	All Cases	All Cases		Field	:	RED FISH REEF
Case Type :	LEASE CASE			Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :	RED.07.14	SEC REPORT		Reservoir	:	OPEX
				Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2024	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2025	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2026	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2027	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2028	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	315.42	0.00	0.00	0.00	-315.42	-308.86
2015	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-995.46
2016	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-1,616.87
2017	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-2,179.40
2018	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-2,688.64
2019	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-3,149.64
2020	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-3,566.87
2021	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-3,944.57
2022	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-4,286.49
2023	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-4,596.03
2024	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-4,876.17
2025	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-5,129.77
2026	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-5,359.35
2027	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-5,567.18
2028	1.00	0.00	0.00	0.00	752.16	0.00	0.00	0.00	-752.16	-5,755.27
Rem.		0.00	0.00	0.00	1,443.66	0.00	0.00	0.00	-1,443.66	-312.55
Total		0.00	0.00	0.00	12,289.32	0.00	0.00	0.00	-12,289.32	-6,067.83

Major Phase :	Gas			Abandonment Date :	12/1/2030
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	0.00	Mcf/month		Revenue Int :	0.81000000	PW	5.00% :	-8,402.89
Abandonment :	0.00	Mcf/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-6,067.83
Initial Decline :	0.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-4,602.89
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	-3,642.53
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	-2,985.36
						PW	30.00% :	-2,517.19

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

75

Date :      08/21/2014 11:45:32AM
		ECONOMIC SUMMARY PROJECTION		Field Expense Rsv Class & Category
Project Name :	HYDROCARB ENERGY 06/30/2014	As Of Date :	07/31/2014	TRINITY BAY Field
Partner :	All Cases	Discount Rate (%) :	10.00
Case Type :	REPORT BREAK TOTAL CASE	All Cases
		SEC REPORT
Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	2.00	0.00	0.00	0.00	444.03	0.00	0.00	0.00	-444.03	-434.80
2015	2.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-1,401.33
2016	2.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-2,276.10
2017	2.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-3,067.98
2018	2.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-3,784.86
2019	2.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-4,433.82
2020	2.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-5,021.17
2021	2.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-5,552.86
2022	2.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-6,034.19
2023	1.00	0.00	0.00	1,442.65	0.00	0.00	0.00	0.00	-1,442.65	-6,642.71
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		0.00	0.00	1,442.65	8,914.68	0.00	0.00	0.00	-10,357.33	-6,642.71

		Present Worth Profile (M$)
		PW	5.00% :	-8,214.56
Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-6,642.71
ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-5,473.27
Years to Payout :	0.00	PW	20.00% :	-4,590.41
Internal ROR (%) :	0.00	PW	25.00% :	-3,913.86
		PW	30.00% :	-3,387.56

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

76

Date :      08/21/2014 11:45:32AM
		ECONOMIC PROJECTION
		As Of Date :	07/31/2014	Case	:	FIELD ABANDONMENT EXPENSE
Project Name :	HYDROCARB ENERGY 06/30/2014	Discount Rate (%) :	10.00	Reserve Cat.	:	Field Expense
Partner :	All Cases	All Cases		Field	:	TRINITY BAY
Case Type :	LEASE CASE			Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :	RED.07.14	SEC REPORT		Reservoir	:	OPEX
				Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :	0.00
Cum Gas (MMcf) :	0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	1.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2023	1.00	0.00	0.00	1,442.65	0.00	0.00	0.00	0.00	-1,442.65	-608.52
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		0.00	0.00	1,442.65	0.00	0.00	0.00	0.00	-1,442.65	-608.52

Major Phase :	Oil			Abandonment Date :	4/30/2023
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	0.00	bbl/month		Revenue Int :	0.81233864	PW	5.00% :	-936.11
Abandonment :	0.00	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-608.52
Initial Decline :	0.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-396.27
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	-258.51
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	-168.93
						PW	30.00% :	-110.59

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

77

Date :      08/21/2014 11:45:32AM
			ECONOMIC PROJECTION
			As Of Date :	07/31/2014	Case	:	FIELD FIXED OPERATING EXPEN
Project Name :	HYDROCARB ENERGY 06/30/2014		Discount Rate (%) :	10.00	Reserve Cat.	:	Field Expense
Partner :	All Cases		All Cases		Field	:	TRINITY BAY
Case Type :	LEASE CASE				Operator	:	GALVESTON BAY ENERGY LLC
Archive Set :	RED.07.14		SEC REPORT		Reservoir	:	OPERATING EXPENSE
					Co., State	:	CHAMBERS, TX
Cum Oil (Mbbl) :		0.00
Cum Gas (MMcf) :		0.00

	Gross	Gross	Net	Net	Oil	Gas	Oil	Gas	Misc.
Year	Oil	Gas	Oil	Gas	Price	Price	Revenue	Revenue	Revenue
	(Mbbl)	(MMcf)	(Mbbl)	(MMcf)	($/bbl)	($/Mcf)	(M$)	(M$)	(M$)
2014	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2015	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2016	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2017	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2018	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2019	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2020	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2021	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
2022	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Rem	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Ult	0.00	0.00

	Well	Net Tax	Net Tax	Net	Net	Net	Other	Net	Annual	Cum Disc.
Year	Count	Production	AdValorem	Investment	Lease Costs	Well Costs	Costs	Profits	Cash Flow	Cash Flow
		(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
2014	1.00	0.00	0.00	0.00	444.03	0.00	0.00	0.00	-444.03	-434.80
2015	1.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-1,401.33
2016	1.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-2,276.10
2017	1.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-3,067.98
2018	1.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-3,784.86
2019	1.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-4,433.82
2020	1.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-5,021.17
2021	1.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-5,552.86
2022	1.00	0.00	0.00	0.00	1,058.83	0.00	0.00	0.00	-1,058.83	-6,034.19
Rem.		0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00
Total		0.00	0.00	0.00	8,914.68	0.00	0.00	0.00	-8,914.68	-6,034.19

Major Phase :	Oil			Abandonment Date :	1/1/2023
Perfs :	0 - 0			Working Int :	1.00000000	Present Worth Profile (M$)
Initial Rate :	0.00	bbl/month		Revenue Int :	0.81233864	PW	5.00% :	-7,278.45
Abandonment :	0.00	bbl/month		Disc. Initial Invest. (M$) :	0.00	PW	10.00% :	-6,034.19
Initial Decline :	0.00	% year	b = 0.000	ROInvestment (disc/undisc) :	0.00 / 0.00	PW	15.00% :	-5,077.00
Beg Ratio :	0.000			Years to Payout :	0.00	PW	20.00% :	-4,331.90
End Ratio :	0.000			Internal ROR (%) :	0.00	PW	25.00% :	-3,744.93
						PW	30.00% :	-3,276.97

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

78

XML

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Cash paid during the period for [Abstract]
Income taxes	$ 10,000	$ 42,483
Interest	21,497	207,269
NONCASH INVESTING AND FINANCING ACTIVITIES
Issuance of HEC common stock to settle notes payable	3,589,567	0
Preferred stock exchanged for HCN preferred stock for acquisition of HCN	3,275,200	0
Receivable for common stock	1,859,879	0
Settlement of HCN debt with HCN preferred stock	1,585,200	1,690,000
Receivable for common stock - related party	1,000,000	0
Note payable for prepaid insurance	403,104	260,905
Asset retirement obligation sold	33,195	438
Common stock exchanged for HCN common stock for acquisition of HCN	8,397	0
Common stock issued to satisfy contingently issuable shares from 2012 acquisition of Namibia Exploration , Inc.	7,470	0
Asset retirement obligations - change in estimate	(104,237)	786,120
Treasury stock acquired via note receivable	0	822,250
Acquisition of Namibia Exploration, Inc.	0	562,048
Expiration of derivative warrant liability	0	269,164
Accounts payable for oil and gas properties	0	188,607
Asset retirement obligations incurred	$ 0	$ 26,500

XML

Related Party Transactions (Details) (USD $)	12 Months Ended		0 Months Ended	1 Months Ended				3 Months Ended
	Jul. 31, 2014	Jul. 31, 2013	Sep. 06, 2012	Oct. 31, 2013	Feb. 28, 2013 acre	Oct. 31, 2012	Aug. 31, 2013	Apr. 30, 2014	Oct. 31, 2013	Sep. 30, 2013
Related Party Transaction [Line Items]
Revenue generated from Barge Canal properties	$ 39,274	$ 643,203
Lease operating costs incurred from Barge Canal properties	23,259	224,047
Overhead costs incurred	0	28,038
Outstanding accounts receivable at period end	0	91,967
Outstanding accounts payable at year end	0	0
Due to related parties	165,542	301,378
Namibia Exploration, Inc. [Member]
Related Party Transaction [Line Items]
Stock issued during period for acquisition, shares (in shares)			8,396,667
HCN [Member]
Related Party Transaction [Line Items]
Interest and late fees				553,630
Father-In-Law of Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Expense recognized from consulting contract with related party		196,384
Interst expense	0
Carter E&P [Member]
Related Party Transaction [Line Items]
Percentage of working interest sold (in hundredths)					2.00%
Number of acre tract of unevaluated property (in acres)					366.85
Land acquisition costs					1,541
Galveston Bay Energy, LLC [Member] | Namibia Exploration, Inc. [Member]
Related Party Transaction [Line Items]
Stock issued during period for acquisition, shares (in shares)						8,396,667
Father Of Chief Financial Officer [Member]
Related Party Transaction [Line Items]
Percentage working interest purchased (in hundredths)	5.00%
Outstanding billed and unbilled joint interest billings owed by related party	58,014	84,806
Due to related parties	0	15,046
Terminated Officer in Corpus Christi Office [Member]
Related Party Transaction [Line Items]
Cash consideration associated with conveying properties to terminated officer							0
Chairman' Nephew [Member]
Related Party Transaction [Line Items]
Stock issued during period for acquisition, shares (in shares)									191,667
Due from employee										1,000,000
Proceeds from Related Party Debt								(675,000)
Chairman' Nephew [Member] | Proceeds From Sale Of Stock [Member]
Related Party Transaction [Line Items]
Proceeds from Related Party Debt								(275,000)
Chairman' Nephew [Member] | Proceeds from loan [Member]
Related Party Transaction [Line Items]
Proceeds from Related Party Debt								(400,000)
Unrelated party in which Michael Watts has minority interest [Member]
Related Party Transaction [Line Items]
Due from employee				1,859,879					1,859,879
Unrelated party in which Michael Watts has minority interest [Member] | Settled with a receivable [Member]
Related Party Transaction [Line Items]
Proceeds from Related Party Debt									750,000
HCN obligation [Member]
Related Party Transaction [Line Items]
Stock issued during period for acquisition, shares (in shares)									619,960
Due to related parties				2,400,000					2,400,000
Interest and late fees									553,630
HCN obligation [Member] | Settled with cash [Member]
Related Party Transaction [Line Items]
Interest and late fees									25,000

XML

Capital Stock, Stock Split, Preferred Stock and Common Stock (Details) (USD $)	0 Months Ended			1 Months Ended		12 Months Ended		0 Months Ended					1 Months Ended
	May 08, 2014	Dec. 04, 2013	Sep. 06, 2013	Oct. 31, 2013	Aug. 31, 2013	Jul. 31, 2014	Jul. 31, 2013	Aug. 04, 2014	Sep. 06, 2013	Dec. 09, 2013	Dec. 02, 2013	Dec. 03, 2013	Oct. 31, 2014	Nov. 29, 2013	Feb. 28, 2013	Dec. 31, 2013	Sep. 30, 2012
Class of Stock [Line Items]
Reverse stock split	1:3 reverse split
Stock split conversion ratio	3
Common stock, shares authorized (in shares)						333,333,333	333,333,333							166,666,667
Common stock, par value (in dollars per share)						$ 0.001	$ 0.001							$ 0.001
Preferred stock, shares issued (in shares)						4,225
Dividends earned						$ 150,548	$ 0
Common stock, shares issued (in shares)						21,081,602	4,427,071
Par value of common stock issued						21,082	4,427
Additional Paid in Capital						78,953,599	75,137,401
Stock issued, business acquisition							35,396,800
Advances from affiliates cancelled						1,379,891
Interest and dividends settled						205,309
Settlement of HCN debt with HCN preferred stock						1,585,200	1,690,000
Maximum percentage of proceeds to be received upon sale of stock to third party (in hundredths)		100.00%	95.00%						95.00%
Maximum proceeds to be received upon sale of stock to third party			1,000,000						1,000,000
Period of stock listing on major stock exchange within which the Company will receive proceeds from sale of stock		90 days	90 days
Period of six month anniversary of stock sale within which the Company will receive proceeds from sale of stock		60 days
Period from date that shares become unrestricted within which the Company will receive proceeds from sale of stock		60 days
Percentage of remaining receivable balance is due within stock listing period (in hundredths)		100.00%
Minimum share price for note receivable to be due to company (in dollars per share)		$ 6.00
Expected life				6 years 6 months	6 years 6 months
2013 Stock Incentive Plan [Member]
Class of Stock [Line Items]
Shares authorized for issuance (in share)						570,136									883,333
Expected life						4 years 6 months
Subsequent Event [Member]
Class of Stock [Line Items]
Period of stock listing on major stock exchange within which the Company will receive proceeds from sale of stock								60 days
Note receivable extension fee								50,000
Note payble remaining balance repaid in future								750,000
HCN [Member]
Class of Stock [Line Items]
Interest and late fees				553,630
Par value of common stock issued										8,397
Additional Paid in Capital										599,409						1,837
Number of shares of common stock issued in exchange for note receivable (in shares)		619,960							191,667
Value of common stock issued in exchange for note receivable		1,859,879							1,000,000
Proceeds from collection of note receivable						675,000
NEI [Member]
Class of Stock [Line Items]
Common stock, shares issued (in shares)																	2,830,000
Commitment to issue additional stock																	31,612,000
Par value of common stock issued																	3,784,800
Series A Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate (in hundredths)										7.00%	7.00%
Preferred stock, shares authorized (in shares)											10,000
Preferred stock stated value (in dollars per share)										$ 400	$ 400
Preferred stock, conversion rate (in dollars per share)											$ 6.00
Preferred stock, shares issued (in shares)						3,963				8,188
Preferred stock										3,275,200
Preferred Stock, Value, Beneficial Conversion Feature										949,808
Dividends earned						34,254						39,230
Series A Preferred Stock [Member] | HCN [Member]
Class of Stock [Line Items]
Preferred stock										3,275,200
Common Stock [Member]
Class of Stock [Line Items]
Stock issued for notes payable and joint interest billings (in shares)													619,960
Consulting fee payable				2,400,000
Joint interest billings payable				635,937
Stock issued for notes payable and joint interest billings													3,589,567
Par value of common stock issued						168
Shares issued for services rendered (in shares)						167,907
Compensation expense for shares issued for services						813,827
Common Stock [Member] | NEI [Member]
Class of Stock [Line Items]
Stock issued during period for acquisition, shares (in shares)						7,470,000				8,396,667
Stock issued, business acquisition										$ 31,612,000

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Changes in Standardized Measure) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Standardized measure of discounted future net cash flows at beginning of year	$ 6,352,793	$ 33,663,886
Net changes in prices and production costs	20,980,014	(37,623,010)
Changes in estimated future development costs	(764,412)	4,205,045
Sales of oil and gas produced, net of production costs	(151,783)	(2,510,339)
Discoveries and extensions	0	0
Purchases of minerals in place	0	0
Sales of minerals in place	(2,228,023)	(17)
Revisions of previous quantity estimates	8,885,117	(12,391,911)
Development costs incurred	0	1,124,107
Change in income taxes	(9,694,393)	14,705,973
Accretion of discount	977,353	5,179,059
Standardized measure of discounted future net cash flows at year end	$ 24,356,666	$ 6,352,793

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Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Income Taxes [Abstract]
Net loss before income taxes	$ (6,550,250)	$ (37,657,165)
Net operating loss carry forwards	$ 15,732,204
Beginning year of expiration of operating loss carry forwards	Jan. 01, 2027

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Fair Value (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended
	Oct. 31, 2009	Jul. 31, 2011	Jul. 31, 2014	Jul. 31, 2013	Nov. 13, 2012	Jul. 31, 2012
Fair Value [Abstract]
Discount to market price (in hundredths)	65.00%
Number of warrants expired (in shares)					206,400
Antidilution provisions expire term for the warrant agreement (in years)	3 years
Warrants Granted To Related Party [Line Items]
Exercise price (in dollars per share)			$ 7.50	$ 7.50		$ 7.74
Warrant B [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price		5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)		$ 22.50
Number of warrants exercisable upon attaining target average closing price (in shares)		200,000
Exercise price (in dollars per share)		$ 7.50
Expiration date		Feb. 15, 2016
Term of warrants		2 years 0 months 29 days
Warrant C [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price		5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)		$ 45.00
Number of warrants exercisable upon attaining target average closing price (in shares)		200,000
Exercise price (in dollars per share)		$ 7.50
Expiration date		Feb. 15, 2016
Term of warrants		2 years 5 months 26 days
Geoserve Marketing, LLC [Member]
Warrants Granted To Related Party [Line Items]
Total shares of common stock issuable under warrants (in shares)		400,000
Geoserve Marketing, LLC [Member] | Warrant B [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price		5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)		$ 22.50
Number of warrants exercisable upon attaining target average closing price (in shares)		200,000
Exercise price (in dollars per share)		$ 7.50
Expiration date		Feb. 15, 2016
Geoserve Marketing, LLC [Member] | Warrant C [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price		5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)		$ 45.00
Number of warrants exercisable upon attaining target average closing price (in shares)		200,000
Exercise price (in dollars per share)		$ 7.50
Expiration date		Feb. 15, 2016

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Commitments and Contingencies (Tables)

12 Months Ended

Jul. 31, 2014

Commitments and Contingencies [Abstract]

Schedule of Prepaid Balances

During the year ended July 31, 2014 and 2013 we prepaid the fees associated with the Greenbank letters of credit for the respective year interest upfront and amortized these fees on a straight-line basis over their respective annual periods. The following table reflects the prepaid balances as follows:

July 31,	2014			2013
Prepaid letter of credit feees	$	101,251		$	101,850
Amortization		(8,488	)		(8,488	)
Net prepaid letter of credit fees	$	92,763		$	93,362

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Income Taxes (Schedule of Deferred Tax Assets) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Income Taxes [Abstract]
Stock based compensation	$ 338,078	$ 713,867
Property, including depreciable property	(3,122,873)	(2,980,005)
Asset retirement obligation	4,168,049	3,942,918
Net operating loss carry-forward	5,596,732	3,846,783
Other	20,860	42,368
Deferred tax assets, gross	7,000,846	5,565,931
Valuation allowance for deferred tax assets	(7,000,846)	(5,565,931)
Total deferred tax assets	$ 0	$ 0

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Results of Operations for Producing Activities) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Net revenues from production	$ 5,065,096	$ 7,070,540
Expenses [Abstract]
Lease operating expense	4,913,313	4,560,201
Accretion	1,043,928	1,056,508
Operating expenses	5,957,241	5,616,709
Depreciation, depletion, and amortization	873,942	1,059,803
Total expenses	6,831,183	6,676,512
Income before income tax	(1,766,087)	394,028
Income tax expenses	0	(137,910)
Results of operations	(1,766,087)	256,118
Depreciation, depletion and amortization rate per net equivalent MCFE	$ 2.04	$ 1.95

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Jul. 31, 2014

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

As of and For the year ended July 31,	2014			2013
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Income taxes	$	10,000		$	42,483
Interest	$	21,497		$	207,269
NONCASH INVESTING AND FINANCING ACTIVITIES
Issuance of HEC common stock to setle notes payable	$	3,589,567			-
Preferred stock exchanged for HCN preferred stock for acquisition of HCN	$	3,275,200		$	-
Receivable for common stock	$	1,859,879		$	-
Settlement of HCN debt with HCN preferred stock	$	1,585,200		$	1,690,000
Receivable for common stock - related party	$	1,000,000		$	-
Note payable for prepaid insurance	$	403,104		$	260,905
Asset retirement obligation sold	$	33,195		$	438
Common stock exchanged for HCN common stock for acquisition of HCN	$	8,397		$	-
Common stock issued to satisfy contingently issuable shares from 2012 acquisition of Namibia Exploration , Inc.	$	7,470		$	-
Asset retirement obligations - change in estimate	$	(104,237	)	$	786,120
Treasury stock acquired via note receivable	$	-		$	822,250
Acquisition of Namibia Exploration, Inc.	$	-		$	562,048
Expiration of derivative warrant liability	$	-		$	269,164
Accounts payable for oil and gas properties	$	-		$	188,607
Asset retirement obligations incurred	$	-		$	26,500

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Capital Stock, Options Outstanding and Exercisable (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Options Outstanding and Exercisable [Line Items]
Outstanding Number of Shares (in shares)	265,333	512,000
Exercisable Number of Shares (in shares)	265,333	258,933
Exercise Price 6.60 [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price (in dollars per share)	$ 6.60	$ 6.60
Outstanding Number of Shares (in shares)	200,000	200,000
Remaining Life	8 years 6 months 14 days	9 years 6 months 14 days
Exercisable Number of Shares (in shares)	200,000	0
Exercise Price 7.50 [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price (in dollars per share)	$ 7.50	$ 7.50
Outstanding Number of Shares (in shares)	53,333	265,333
Remaining Life	6 years 8 months 23 days	7 years 8 months 23 days
Exercisable Number of Shares (in shares)	53,333	212,267
Exercise Price 7.50 [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price (in dollars per share)	$ 7.50	$ 7.50
Outstanding Number of Shares (in shares)	4,000	20,000
Remaining Life	4 years 9 months 22 days	3 years 11 months 5 days
Exercisable Number of Shares (in shares)	4,000	20,000
Exercise Price 7.50 [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price (in dollars per share)	$ 7.50	$ 7.50
Outstanding Number of Shares (in shares)	8,000	8,000
Remaining Life	2 years 11 months 5 days	5 years 9 months 22 days
Exercisable Number of Shares (in shares)	8,000	8,000
Exercise Price 7.50 [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price (in dollars per share)		$ 7.50
Outstanding Number of Shares (in shares)		18,667
Remaining Life		1 year
Exercisable Number of Shares (in shares)		18,667

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Oil and Gas Properties (Details) (USD $)	12 Months Ended		1 Months Ended		0 Months Ended
	Jul. 31, 2014	Jul. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Sep. 06, 2012	Dec. 31, 2013
Oil And Gas Properties [Line Items]
Geological And Geophysical Costs	$ 34,029	$ 157,818
Cash proceeds on termination of employment	0
Assumption of abandonment liabilities	4,381
Recognized gain (loss) on sale	0
Proceeds from sale of oil and gas properties	625,000	195,563
Asset retirement obligation sold	33,195	438
Exploration costs	238,112	404,265
Janssen lease [Member]
Oil And Gas Properties [Line Items]
Proceeds from sale of working interest			2,500
Percentage of working interest sold (in hundredths)			3.00%
Asset retirement obligation sold			438
Welder Lease [Member]
Oil And Gas Properties [Line Items]
Number of productive wells on the property	2
Holt And Strahan Properties [Member]
Oil And Gas Properties [Line Items]
Ownership percentage (in hundredths)				6.25%
Proceeds from sale of working interest				50,000
Portion of overriding royalty interest treated as reduction of capitalized costs				32,146
Namibia Exploration, Inc. [Member]
Oil And Gas Properties [Line Items]
Acquisition related costs, cash paid	1,406,114	713,655
Ownership percentage (in hundredths)				39.00%
Number of acres included in oil and gas property				5,300,000
Cost responsibility percentage (in hundredths)				43.33%	43.33%
Cost basis in working interest in oil and gas property	562,048	562,048			562,048
Minimum cost responsibilities during initial exploration period	4,505,000
Minimum cost responsibilities during the first renewal exploration period	17,350,000
Percentage of relinquish exploration license area during the first renewal exploration period (in hundredths)	25.00%
Minimum cost responsibilities during the second renewal exploration period	300,000
Second renewal exploration period	25 years
The cumulative amount expended toward costs for the initial exploration period	2,100,000	900,000
Exploration costs	800,000
Leasehold costs	$ 129,000
HCN [Member]
Oil And Gas Properties [Line Items]
Ownership percentage (in hundredths)	90.00%					51.00%
Cost responsibility percentage (in hundredths)	100.00%					56.67%

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Acquisitions, HCN (Details) (USD $)	0 Months Ended
	Dec. 09, 2013 Well acre	Dec. 02, 2013	Jul. 31, 2014	Jul. 31, 2013	Dec. 31, 2013
Summary of the accounting entry to record the acquisition [Abstract]
Common stock, at par			$ 21,082	$ 4,427
Receivable for common stock			(2,184,879)	0
Additional paid-in capital			78,953,599	75,137,401
Recorded Unconditional Purchase Obligation [Line Items]
Working interest rights (in hundredths)	39.00%		90.00%
Cost responsibility rate (in hundredths)			100.00%
Concession area	5,300,000
Number of wells required to be drilled under the purchase obligation	1
Initial Exploration Period [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Area of seismic data required by purchase obligation	750
Minimum required expenditure	4,505,000
First Renewal Exploration Period [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Duration of commitment period	2 years
Area of seismic data required by purchase obligation	200
Minimum required expenditure	17,350,000
Percentage of exploration license area relinquish requirement (in hundredths)	25.00%
Second Renewal Exploration Period [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Duration of commitment period	25 years
Minimum required expenditure	300,000
Common Stock [Member]
Summary of the accounting entry to record the acquisition [Abstract]
Common stock, at par			168
Series A Preferred Stock [Member]
Summary of the accounting entry to record the acquisition [Abstract]
Series A 7% Preferred Stock, par $400	3,275,200
Dividend rate of preferred stock (in hundredths)	7.00%	7.00%
Preferred stock stated value (in dollars per share)	400	$ 400
HCN [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares reserved for issuance to certain stock holders with certain rights (in shares)	7,470,000
Shares issued and sold to extinguish debt (in shares)	619,960
Value of shares issued to extinguish debt	3,589,567
Summary of the accounting entry to record the acquisition [Abstract]
Assets acquired	1,529,246
Liabilities assumed	(161,599)
Noncontrolling interest in 95% owned HCN subsidiary	30,480
Total	1,398,127
Common stock, at par	8,397
Receivable for common stock	(2,484,879)
Additional paid-in capital	599,409				1,837
Recorded Unconditional Purchase Obligation [Line Items]
Working interest rights (in hundredths)	51.00%
HCN [Member] | Series A Preferred Stock [Member]
Summary of the accounting entry to record the acquisition [Abstract]
Series A 7% Preferred Stock, par $400	3,275,200
HCN [Member] | Common Stock [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Number of shares exchanged (in shares)	8,396,667
Value of shares issued for acquisition	64,990,200
HCN [Member] | Preferred Stock [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Number of shares exchanged (in shares)	8,188
Value of shares issued for acquisition	3,275,200
Per share value of shares issued for acquisition (in dollars per share)	400
Hydrocarb Namibia Energy (Pty) Limited [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Percentage ownership in subsidiaries (in hundredths)	100.00%
Otaiba Hydrocarb LLC [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Percentage ownership in subsidiaries (in hundredths)	95.00%

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Capital Stock, Warrants Granted (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013	Jul. 31, 2012	Jul. 31, 2011
Warrants Granted To Related Party [Line Items]
Exercise price (in dollars per share)	$ 7.50	$ 7.50	$ 7.74
Compensation expense recognized	$ 1,757,399	$ 933,126
Warrants [Roll Forward]
Outstanding, beginning balance (in shares)	1,236,959	1,252,152
Granted (in shares)	0	0
Exercised (in shares)	0	0
Expired (in shares)	(152,375)	(15,193)
Outstanding, beginning balance (in shares)	1,084,584	1,236,959	1,252,152
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)	$ 7.50	$ 7.74
Granted (in dollars per share)	$ 0	$ 0
Exercised (in dollars per share)	$ 0	$ 0
Expired (in dollars per share)	$ 7.50	$ 28.02
Outstanding, beginning balance (in dollars per share)	$ 7.50	$ 7.50	$ 7.74
Aggregate intrinsic value	0	0	0
Weighted average remaining contractual life	1 year 0 months 14 days	1 year 10 months 13 days	2 years 9 months 29 days
Warrant B [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price				5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)				$ 22.50
Number of warrants exercisable upon attaining target average closing price (in shares)				200,000
Exercise price (in dollars per share)				$ 7.50
Expiration date				Feb. 15, 2016
Fair value	266,017
Compensation expense recognized	6,754
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)				$ 7.50
Warrant C [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price				5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)				$ 45.00
Number of warrants exercisable upon attaining target average closing price (in shares)				200,000
Exercise price (in dollars per share)				$ 7.50
Expiration date				Feb. 15, 2016
Fair value	206,245
Compensation expense recognized		$ 196,384
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)				$ 7.50
Geoserve Marketing, LLC [Member]
Warrants Granted To Related Party [Line Items]
Total shares of common stock issuable under warrants (in shares)				400,000
Geoserve Marketing, LLC [Member] | Warrant B [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price				5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)				$ 22.50
Number of warrants exercisable upon attaining target average closing price (in shares)				200,000
Exercise price (in dollars per share)				$ 7.50
Expiration date				Feb. 15, 2016
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)				$ 7.50
Geoserve Marketing, LLC [Member] | Warrant C [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price				5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)				$ 45.00
Number of warrants exercisable upon attaining target average closing price (in shares)				200,000
Exercise price (in dollars per share)				$ 7.50
Expiration date				Feb. 15, 2016
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)				$ 7.50

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Costs Excluded by Year) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Property Acquisition	$ 1,232,815	$ 677,795
Exploration	173,299	35,860
Total	$ 1,406,114	$ 713,655

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Additional Financial Statement Information (Schedule of Accounts Payable and Accrued Expenses) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Additional Financial Statement Information [Abstract]
Trade payables	$ 2,686,966	$ 2,503,820
Accrued payroll	(76,064)	151,577
Accrued interest and fees	37,853	500
Revenue payable	5,790	4,717
Local taxes and royalty payable	111,699	128,470
Federal and state income taxes payable	29,431	27,000
Total accounts payable and accrued expenses	$ 2,795,675	$ 2,816,084

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Fair Value (Schedule of the Changes in Fair Value of the Warrant Liability) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Fair Value [Abstract]
Beginning of the period	$ 0	$ 1,325,388
Expiration of derivative warrant feature	0	(269,164)
Unrealized gain on changes in fair value of derivative liability	0	(1,056,224)
End of the period	$ 0	$ 0

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Supplemental Cash Flow Information

12 Months Ended

Jul. 31, 2014

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information [Text Block]

Note 3 – Supplemental Cash Flow Information

As of and For the year ended July 31,	2014			2013
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Income taxes	$	10,000		$	42,483
Interest	$	21,497		$	207,269
NONCASH INVESTING AND FINANCING ACTIVITIES
Issuance of HEC common stock to setle notes payable	$	3,589,567			-
Preferred stock exchanged for HCN preferred stock for acquisition of HCN	$	3,275,200		$	-
Receivable for common stock	$	1,859,879		$	-
Settlement of HCN debt with HCN preferred stock	$	1,585,200		$	1,690,000
Receivable for common stock - related party	$	1,000,000		$	-
Note payable for prepaid insurance	$	403,104		$	260,905
Asset retirement obligation sold	$	33,195		$	438
Common stock exchanged for HCN common stock for acquisition of HCN	$	8,397		$	-
Common stock issued to satisfy contingently issuable shares from 2012 acquisition of Namibia Exploration , Inc.	$	7,470		$	-
Asset retirement obligations - change in estimate	$	(104,237	)	$	786,120
Treasury stock acquired via note receivable	$	-		$	822,250
Acquisition of Namibia Exploration, Inc.	$	-		$	562,048
Expiration of derivative warrant liability	$	-		$	269,164
Accounts payable for oil and gas properties	$	-		$	188,607
Asset retirement obligations incurred	$	-		$	26,500

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Subsequent Events (Details) (USD $)	0 Months Ended
	Nov. 06, 2014	Aug. 15, 2014	May 31, 2012
Subsequent Event [Line Items]
Term Loan face amount			$ 18,375
Subsequent Event [Member]
Subsequent Event [Line Items]
Interest rate in case of default (in hundredths)		24.00%
Voting stock percentage (in hundredths)		25.00%
Common stock issued in settlement (in shares)	65,000
Subsequent Event [Member] | Galveston Bay, LLC [Member]
Subsequent Event [Line Items]
Cash payment settlement	35,000
Subsequent Event [Member] | Term Loan [Member]
Subsequent Event [Line Items]
Term Loan face amount		4,000,000
Term Loan amount outstanding		4,545,454
Discount rate (in hundredths )		12.00%
Structuring fee		90,909
Structuring fee (in hundredths)		2.00%
Debt Issuance Cost		172,824
Placement fee (in hundredths)		5.00%
Placement fee		227,273
Consulting fee (in hundredths)		1.00%
Consulting Fee		45,455
Proceed from long term debt		3,463,539
Additional borrowing capacity		1,000,000
Sale of equity		750,000
Credit agreement period sale of equity		150 days
Structuring Fee on additional borrowings (in hundredths)		2.00%
Threshold Revenues		900,000
Interest rate under condition one (in hundredths)		16.00%
Interest rate under condition two (in hundredths)		14.00%
Restricted shares issued		60,000
Restricted shares issued after 12 months from effective date (in shares)		32,500
Restricted shares issued after 18 months from effective date (in shares)		32,500
Restricted shares issued after 21 months from effective date (in shares)		25,000
Credit agreement effective date		Aug. 15, 2014
Payables in case of default		250,000
Period of default		30 days

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Asset Retirement Obligation (Details) (USD $)	12 Months Ended
	Jul. 31, 2014 Well	Jul. 31, 2013
Reconciliation of asset retirement obligation balance [Abstract]
Liability for asset retirement obligation, beginning of period	$ 10,933,398	$ 9,382,933
Asset retirement obligations sold	(33,195)	(438)
Asset retirement obligation incurred on properties drilled	0	26,500
Accretion	1,043,928	1,056,508
Revisions in estimated cash flows	(104,237)	786,120
Costs incurred	(123,664)	(318,225)
Liability for asset retirement obligation, end of period	11,716,230	10,933,398
Current portion of asset retirement obligation	1,133,690	724,374
Noncurrent portion of asset retirement obligation	10,582,540	10,209,024
Total liability for asset retirement obligation	11,716,230	10,933,398
Estimated Timing of asset retirement obligation payments [Abstract]
2015	1,133,690
2016	727,241
2017	1,194,856
2018	618,215
2019	857,144
2020 to 2024	4,291,988
2025 to 2029	1,660,378
2030 to 2034	1,232,718
Thereafter	0
Total liability for asset retirement obligation	11,716,230	10,933,398
Number of wells plugged	3
Pipelines [Member]
Reconciliation of asset retirement obligation balance [Abstract]
Liability for asset retirement obligation, end of period	1,655,939
Total liability for asset retirement obligation	1,655,939
Estimated Timing of asset retirement obligation payments [Abstract]
2015	126,290
2016	60,000
2017	99,938
2018	55,040
2019	52,621
2020 to 2024	980,713
2025 to 2029	236,898
2030 to 2034	44,439
Thereafter	0
Total liability for asset retirement obligation	1,655,939
Number of dismantlement, restoration or abandonment obligations	45
Easements [Member]
Reconciliation of asset retirement obligation balance [Abstract]
Liability for asset retirement obligation, end of period	523,995
Total liability for asset retirement obligation	523,995
Estimated Timing of asset retirement obligation payments [Abstract]
2015	0
2016	27,516
2017	66,006
2018	14,475
2019	10,429
2020 to 2024	193,283
2025 to 2029	67,089
2030 to 2034	145,197
Thereafter	0
Total liability for asset retirement obligation	523,995
Number of dismantlement, restoration or abandonment obligations	135
Wellbores [Member]
Reconciliation of asset retirement obligation balance [Abstract]
Liability for asset retirement obligation, end of period	6,719,388
Total liability for asset retirement obligation	6,719,388
Estimated Timing of asset retirement obligation payments [Abstract]
2015	997,400
2016	639,725
2017	191,476
2018	548,700
2019	572,337
2020 to 2024	2,269,781
2025 to 2029	1,356,391
2030 to 2034	143,578
Thereafter	0
Total liability for asset retirement obligation	6,719,388
Number of dismantlement, restoration or abandonment obligations	143
Facilities [Member]
Reconciliation of asset retirement obligation balance [Abstract]
Liability for asset retirement obligation, end of period	2,816,908
Total liability for asset retirement obligation	2,816,908
Estimated Timing of asset retirement obligation payments [Abstract]
2015	10,000
2016	0
2017	837,436
2018	0
2019	221,757
2020 to 2024	848,211
2030 to 2034	899,504
Thereafter	0
Total liability for asset retirement obligation	$ 2,816,908
Number of dismantlement, restoration or abandonment obligations	8

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Fair Value (Tables)

12 Months Ended

Jul. 31, 2014

Fair Value [Abstract]

Reconciliation of the Changes in Fair Value Measurement of Level 3 Derivative Warrant Liabilities

The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability as follows:

As of July 31,	2014		2013
Beginning of period	$	-	$	1,325,388
Expiration of derivative warrant feature		-		(269,164	)
Unrealized gain on changes in fair value of derivative liability		-		(1,056,224	)
End of period	$	-	$	-

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Notes Payable (Tables)

12 Months Ended

Jul. 31, 2014

Notes Payable [Abstract]

Maturities of long term debt obligation

Maturities of our long term debt obligation at July 31, 2014 are as follows:

Year ending July 31,	2015		Thereafter		Total
Operating and capital leases	$	-	$	-	$	-
Notes payable		334,688		-		334,688
Total	$	334,688	$	-	$	334,688

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Income Taxes (Reconciliation of Income Tax Provision at the Statutory Rate) (Details)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Income Taxes [Abstract]
US statutory federal rate (in hundredths)	35.00%	35.00%
State income tax rate (in hundredths)	0.58%	0.58%
Equity-based compensation (in hundredths)	(5.16%)	(33.62%)
Gain on derivative warrants (in hundredths)	0.00%	0.93%
Gain on sale of securities (in hundredths)	0.00%	(0.33%)
Other (in hundredths)	(6.64%)	(0.50%)
Net operating loss (in hundredths)	(23.70%)	(1.75%)
Effective income tax rate (in hundredths)	0.08%	0.31%

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Notes Payable, Lines of Credit (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Mar. 17, 2011
Notes Payable [Abstract]
Revolving line of credit period with commercial bank	1 year
Line of credit, interest rate spread over prime rate (in hundredths)	1.00%
Debt instrument, minimum interest rate (in hundredths)	5.00%
Line of credit, interest rate (in hundredths)	6.00%
Line of credit, amount outstanding	$ 5

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Capital Stock (Tables)

12 Months Ended

Jul. 31, 2014

Capital Stock [Abstract]

Warrants Granted to Related Parties

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

	Warrant B		Warrant C
Fair Value	$	266,017	$	206,245

The following table reflects information regarding Warrant B and Warrant C during the year ended July 31, 2014 and 2013.

	July 31, 2014		July 31, 2013
	Warrant B		Warrant C
Compensation Expense recognized	$	6,754	$	196,384

Stock Options Granted to Nonemployees Under Stock Incentive Plans

The following table provides information about options granted to non-employees under our stock incentive plans during the years ended as follows:

As of July 31,	2014		2013
Number of options granted		-		200,000
Compensation expense recognized	$	887,544	$	679,174
Weighted average exercise price of options granted		N/A	$	6.60

Assumptions Used to Estimate Fair Value of Stock Option Awards

The following table details the significant assumptions used to compute the fair market values of stock options granted or revalued during the years ended as follows:

As of July 31,		2014				2013
Risk-free interest rate	N/A		-	N/A	1.11%		-	2.00%
Dividend yield				0%				0%
Volatility factor	N/A		-	N/A	140.3%		-	144.0%
Expected life (in years)				N/A				6.5

Stock Options Granted to Employees Under Stock Incentive Plans

The following table provides information about options granted to employees under our stock incentive plans.

For the year end July 31,	2014		2013
Number of options granted		-		-
Compensation expense recognized	$	56,028	$	253,952
Weighted average exercise price of options granted		N/A		N/A

Stock Option Activity Under Stock Option and Incentive Plans

Summary information regarding stock options issued and outstanding as follows:

	Options			Weighted average share price		Aggregate intrinsic value		Weighted average remaining contractual life (in years)
Outstanding at July 31, 2012	$	348,000		$	7.50		-		7.22
Granted		200,000			6.60
Exercised		-			-
Expired or forfeited		(36,000	)		7.50
Outstanding at July 31, 2013		512,000			6.81		-		7.98
Granted		-			-
Exercised		-			-
Expired or forfeited		(246,667	)		7.50
Outstanding at July 31, 2014	$	265,333		$	6.81		-		7.95
Exercisable at July 31, 2014	$	265,333		$	6.81		-		7.95

Schedule of Stock Options Outstanding and Exercisable

Options outstanding and exercisable as of July 31, 2014 as follows:

Exercise Price		Outstanding Number of Shares		Remaining Life		Exercisable Number of Shares
$	6.60		200,000		8.54		200,000
$	7.50		53,333		6.73		53,333
$	7.50		4,000		4.81		4,000
$	7.50		8,000		2.93		8,000
			265,333				265,333

Summary information regarding nonvested stock options as of July 31, 2013 is as follows:

Exercise Price		Outstanding Number of Shares		Remaining Life		Exercisable Number of Shares
$	6.60		200,000		9.54		-
$	7.50		265,333		7.73		212,267
$	7.50		20,000		3.93		20,000
$	7.50		8,000		5.81		8,000
$	7.50		18,667	Less than 1 year			18,667
			512,000				258,933

Schedule of Nonvested Share Activity

Summary information regarding nonvested stock options as of July 31, 2014 is as follows:

	Number of shares			Weighted average grant date fair value
Nonvested at July 31, 2013		253,067		$	7.41
Granted		-		$	-
Vested		(6,400	)	$	7.50
Forfeited		(246,667	)	$	7.50
Nonvested at July 31, 2014		-		$	-

Warrant Activity

Summary information regarding common stock warrants issued and outstanding as of July 31, 2014, is as follows:

	Warrants			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (in years)
Outstanding at year ended July 31, 2012		1,252,152		$	7.74	$	-		2.83
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(15,193	)		28.02		-		-
Outstanding at year ended July 31, 2013		1,236,959		$	7.50	$	-		1.87
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(152,375	)		7.50		-		-
Outstanding at year ended July 31, 2014		1,084,584		$	7.50	$	-		1.04

Schedule of Warrants Outstanding and Exercisable

Warrants outstanding and exercisable as of July 31, 2014:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	7.50		666,667	2 years or less		666,667
$	7.50		349,117	1 year or less		349,117
$	7.50		68,800	1 year or less		68,800
			1,084,584			1,084,584

Warrants outstanding and exercisable as of July 31, 2013:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	7.50		666,667	3 years or less		266,667
$	7.50		417,919	2 years or less		417,919
$	7.50		152,373	1 year or less		152,373
			1,236,959			836,959

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Related Party Transactions (Tables)

12 Months Ended

Jul. 31, 2014

Related Party Transactions [Abstract]

Schedule of Revenues and Costs from Facility Controlled by Related Party

Revenues generated, lease operating costs, and contractual overhead charges, which are included in lease operating costs incurred from these properties, were as follows:

Year Ended July 31,	2013		2014
Revenue generated from Barge Canal properties	$	643,203	$	39,274
Lease operating cost incurred from Barge Canal properties	$	224,047	$	23,259
Overhead costs incurred	$	28,038	$	-
Outstanding accounts receivable at period end	$	91,967	$	-
Outstanding accounts payable at year end	$	-	$	-

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Acquisitions

12 Months Ended

Jul. 31, 2014

Acquisitions [Abstract]

Acquisitions

Note 2 – Acquisitions

HCN Acquisition

On December 9, 2013 (“Acquisition Date”), we acquired HCN (“HCN Acquisition”) pursuant to a Share Exchange Agreement (“HCN Agreement”) dated November 27, 2013.  The purchase price was 8,396,667 shares of HEC’s common stock to HCN’s shareholders in exchange for 100% of the outstanding equity interest in HCN and 8,188 shares of HEC Series A Preferred Stock to a holder of convertible preferred stock in HCN in exchange of 100% of the holder’s preferred stock in HCN. At date of closing the 8,396,667 shares of common stock issued had a market valuation of $64,990,200 (based on market close of $7.74 on December 9, 2013) and the preferred stock issued had a value of $3,275,200 (8,188 shares at par value of $400).

In addition, the HCN 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.

In anticipation of the HCN Acquisition, HEC issued 619,960 shares of its common stock to HCN as full payment for HEC’s indebtedness to HCN in the amount of $3,589,567.  A condition to the Agreement closing was that HCN would sell the 619,960 shares before closing of the acquisition, which it did (see Note 10 – Capital Stock – Receivables for Common Stock).

With HCN, we acquired its 100% owned subsidiaries: Hydrocarb Namibia Energy (Pty) Limited, a Namibia Company and Hydrocarb Texas Corporation, a Texas Corporation; and its 95% owned subsidiary Otaiba Hydrocarb LLC, a UAE Limited Liability Company.

Prior to the HCN Acquisition, HCN was directly and indirectly majority-owned and controlled by HEC’s Chairman of the Board and entities related to him and his family.  Since HEC and HCN were under common control of a controlling party both before and after the completion of the share exchange, the transaction was accounted for as a business acquired from an entity under common control and the assets and liabilities acquired were recorded at HCN’s historical cost at Acquisition Date following ASC 805-50-30, Business Combinations.  Under this accounting treatment, the results of operations for the year ended July 31, 2014 and assets and liabilities of HCN are included in these financial statements as if the transaction had occurred at the beginning of the reporting period.  Prior reporting periods in these financial statements have been retroactively adjusted to include HCN and its subsidiaries.

According to ASC 805-50-30, the net assets of HCN are to be recorded at historical cost, therefore, the value of the 8,396,667 common shares and 8,188 preferred shares are deemed to be the same as the historical value of HCN net assets of $1,398,127 with excess of $599,409 recorded as additional paid in capital by HEC.

Summary of the accounting entry to record this acquisition in December 2013 is as follows:

Assets acquired	$	1,529,246
Liabilities assumed		(161,599	)
Noncontrolling interest in 95% owned HCN subsidiary		30,480
	$	1,398,127
Series A 7% Preferred Stock, par $400	$	3,275,200
Common stock, at par		8,397
Receivable for common stock		(2,484,879	)
Additional paid-in capital		599,409
	$	1,398,127

HCN had 51% working-interest rights in and operated an unevaluated onshore petroleum Namibian concession measuring approximately 5.3 million acres and covered by Petroleum Exploration License No. 0038 as issued by the Republic of Namibia Ministry of Mines and Energy. (“Namibian Concession”) described in Note 5 – Oil and Gas Properties, below, and provided international oilfield consulting services.  Prior to this acquisition, HEC owned a 39% working-interest right in this concession see NEI Acquisition below).  With the HCN acquisition, we now own a 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.

Namibia Exploration, Inc. (“NEI”) Acquisition

On August 7, 2012, we entered into a Share Exchange Agreement (the “NEI Agreement”), which was closed on September 6, 2012, under which we purchased NEI, a corporation organized under the laws of the state of Nevada for the issuance of 8,396,667 shares of our common stock as described below (the “NEI Acquisition”).  Prior to the acquisition, NEI was directly and indirectly owned and controlled by HEC’s then-Chief Executive Officer, his brother-in-law, and his father-in-law.

NEI was formed in February 2012 and its sole asset was a 39% working interest (43.33% cost responsibility) in the Namibian Concession. With the acquisition of HCN, the Company now has a 90% working interest (100% cost responsibility) in the Namibian Concession.  HEC now holds working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. ("NPC Namibia").

As NEI had no operations other than the ownership of the Namibian Concession, the transaction was accounted for as an asset purchase from an entity under common control and the asset was recorded at NEI’s historical cost of $562,048 with additional amounts paid considered compensatory and thus an expense of the acquisition.  The consideration included stock granted at the closing of the transaction as well as a series of stock grants that were contingent upon the achievement of certain market conditions.   The value of the total consideration, including contingent stock and the liabilities assumed in excess of NEI’s assets, was computed as described below.  $34,834,752 was reflected in our statement of operations as Acquisition-related costs – related party in conjunction with this transaction.

NEI originally acquired its interests in the Namibian Concession from Hydrocarb Namibia (a subsidiary of HCN) in exchange for a farm-in fee, totaling $2,400,000, payable over two years. At that time HCN was partly owned by the uncle of HEC’s then-Chief Executive Officer’s wife and brother-in-law.  Because the $2,400,000 fee was a related party transaction, and accordingly presumed not to be arms-length, and because there was substantial uncertainty about the realizability of the fees paid to HCN given that the concession was unproved, management concluded that HCN’s historical expenditures of $562,048 (which consists primarily of fees paid to the Namibian government for the concession) represented the fair value of the asset and NEI’s cost basis in the asset. The farm-in agreement also provided for preferential offerings of other international oil and gas opportunities similar to the concession in Namibia.  With the Company’s acquisition of HCN and its accounting for the HCN transaction as the acquisition of a business from an entity under common control, the $2,400,000 fee has been eliminated in consolidation, since these financial statements have been retroactively adjusted to include HCN and its subsidiaries since the beginning of the reporting period herein.

Consideration for the acquisition of NEI

Pursuant to the terms of the Agreement, HEC issued 830,000 shares of common stock in September 2012 at the closing.  An additional 2,490,000 shares were contingently issuable as consideration for the NEI Acquisition, in accordance with the following milestones which were to have been reached within 10 years after the closing of the acquisition:

● a further 830,000 of the Shares will be issued when and if HEC's 10-day volume-weighted average market capitalization reaches $82,000,000;

● a further 2,490,000 of the Shares will be issued when and if HEC's 10-day volume-weighted average market capitalization reaches $196,000,000; and

● a further and final 4,150,000 of the Shares will be issued when and if HEC's 10-day volume-weighted average market capitalization reaches $434,000,000.

NEI’s cost basis in the Namibia Concession was $562,048.   The assets and liabilities were recorded at NEI’s carrying value on the date of the acquisition and the excess purchase price over the net assets acquired was recorded as an acquisition-related expense (compensation) because this was a related party transaction.   The purchase price consisted of the 830,000 shares that were awarded at closing, which were valued using the closing market price of the stock on the date of grant, and the 7,470,000 shares of the contingent stock grant.  The fair value of contingent stock grant was valued in accordance with ASC 820 – Fair Value Measurements.  The determination of fair value used a market approach weighted at 75% and the income approach (discounted cash flows) weighted at 25%.  The computations included consideration of projections of the future results of HEC and NEI, using multiple probability-weighted scenarios, and projections of HEC’s capital structure.  As of July 31, 2013, we had recognized $34,834,752 of expense associated with the acquisition of NEI, which consisted of the assumption of NEI’s net liability of $1,837,952, $3,784,800 associated with the 2,490,000 shares issued at the closing date of the acquisition and $29,212,000 associated with the contingent consideration.

In conjunction with the HCN acquisition in December 2013, the HEC Board of Directors authorized the immediate issuance of these contingently issuable 7,470,000 shares of our common stock to the former owners of NEI.  We issued these shares on December 9, 2013.

Hydrocarb agreement

In conjunction with the execution of the NEI Agreement, and as a condition of Closing, HEC entered into a Consulting Services Agreement with HCN (the "Consulting Agreement"), whereby HCN would provide various consulting services with respect to HEC's business ventures in Namibia and whereby HCN acknowledged and agreed that the obligations of NEI under its existing Farmin Opportunity Report with HCN (the "FOR") would be satisfied in exchange for HEC paying a consulting fee (the "Fee") to HCN of $2,400,000.  As a result of HEC’s acquisition of HCN, this Consulting Agreement and its related income/expense and receivable/payable have been eliminated in consolidation.

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Income Taxes (Tables)

12 Months Ended

Jul. 31, 2014

Income Taxes [Abstract]

Reconciliation of Income Tax Provision at the Statutory Rate

The reconciliation of our income tax provision at the statutory rate to the reported income tax expense is as follows:

As of and For the Year ended July 31,	2014			2013
U.S statutory federal rate		35 00	%		35.00	%
State income tax rate		0.58	%		0.58	%
Equity-based compensation		(5.16	)%		(33.62	)%
Gain on derivative warrants		-	%		0.93	%
Gain on sale of securities		-	%		(0.33	)%
Other		(6.64	)%		(0.50	)%
Net operating loss		(23.70	)%		(1.75	)%
Effective statutory rate		0.08	%		0.31	%

Summary of Deferred Tax Assets

Components of deferred tax assets as of July 31, 2014 and 2013 are as follows:

As of and For the Year ended July 31.	2014			2013
Stock based compensation	$	338,078		$	713,867
Property. including depreciable property		(3,122,873	)		(2,980,005	)
Asset retirement obligation		4,168,049			3,942,918
Net operating loss carry-forward		5,596,732			3,846,783
Other		20,860			42,368
		7,000,846			5,565,931
Valuation allowance for deferred tax assets		(7,000,846	)		(5,565.931	)
Total deferred tax assets	$	-		$	-

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Available for Sale Securities (Details) (USD $)	1 Months Ended			12 Months Ended
	Dec. 31, 2012	Oct. 31, 2012	Sep. 30, 2012	Jul. 31, 2014	Jul. 31, 2013	Jul. 31, 2012
Schedule of Available-for-sale Securities [Line Items]
Proceeds from sale of available for sale securities	$ 142,637		$ 145,237	$ 0	$ 287,874
Cost basis of available for sale securities sold	198,593	174,000	607,201
Impairment of available for sale securities		275,327		0	275,327
Unrealized loss reclassified from other comprehensive loss into earnings	(743,082)					6,383
Market value of available-for-sale securities				0	24,593	702,959
(Gain) loss on sale of available for sale securities	$ 55,956		$ 461,964	$ 0	$ 517,920

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Capital Stock, Warrants Outstanding and Exercisable (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013	Jul. 31, 2012
Warrants Outstanding And Exercisable [Line Items]
Exercise price (in dollars per share)	$ 7.50	$ 7.50	$ 7.74
Outstanding Number of Shares (in shares)	1,084,584	1,236,959	1,252,152
Remaining Life	1 year 0 months 14 days	1 year 10 months 13 days	2 years 9 months 29 days
Exercisable Number of Shares (in shares)	1,084,584	836,959
Exercise Price 7.50 [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise price (in dollars per share)	$ 7.50	$ 7.50
Outstanding Number of Shares (in shares)	666,667	666,667
Remaining Life	2 years	3 years
Exercisable Number of Shares (in shares)	666,667	266,667
Exercise Price 7.50 [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise price (in dollars per share)	$ 7.50	$ 7.50
Outstanding Number of Shares (in shares)	349,117	417,919
Remaining Life	1 year	2 years
Exercisable Number of Shares (in shares)	349,117	417,919
Exercise Price 7.50 [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise price (in dollars per share)	$ 7.50	$ 7.50
Outstanding Number of Shares (in shares)	68,800	152,373
Remaining Life	1 year	1 year
Exercisable Number of Shares (in shares)	68,800	152,373

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CONSOLIDATED BALANCE SHEETS (USD $)	Jul. 31, 2014	Jul. 31, 2013
Current assets:
Cash and cash equivalents	$ 144,258	$ 354,829
Oil and gas revenues receivable	372,120	725,691
Accounts receivable - related party	58,014	201,284
Other current assets	446,320	345,942
Other receivables, net	38,455	312,997
Total current assets	1,059,167	1,940,743
Oil and Gas Property, accounted for using the full cost method of accounting
Evaluated property, net of accumulated depletion of $3,491,420 and $2,617,478, respectively; and accumulated impairment of $373,335 and $373,335, respectively	15,288,370	16,867,029
Unevaluated property	2,119,769	1,124,805
Restricted cash	6,877,944	6,920,739
Other assets	219,942	180,726
Property and equipment, net of accumulated depreciation of $135,590 and $116,945, respectively	166,963	58,053
TOTAL ASSETS	25,732,155	27,092,095
Current liabilities:
Accounts payable and accrued expenses	2,795,675	2,816,084
Current portion of notes payable	334,688	259,644
Asset retirement obligations - short term	1,133,690	724,374
Advances	195,904	180,804
Due to related parties	165,542	301,378
Total current liabilities	4,625,499	4,282,284
Notes payable	0	142,992
Notes payable - related party	600,000	0
Asset retirement obligations - long term	10,582,540	10,209,024
Total liabilities	15,808,039	14,634,300
Stockholders' Deficit:
Common stock: $001 par value; 333,333,333 shares authorized; 20,963,759 and 4,427,071 shares issued and outstanding as of July 31, 2014 and 2013, respectively	21,082	4,427
Receivable for common stock	(2,184,879)	0
Additional paid in capital	78,953,599	75,137,401
Accumulated deficit	(70,106,351)	(63,522,775)
Treasury stock	0	(822,250)
Total stockholders' equity	9,958,651	12,486,803
Noncontrolling interests	(34,535)	(29,008)
Total equity	9,924,116	12,457,795
TOTAL LIABILITIES AND EQUITY	25,732,155	27,092,095
Series A 7% Convertible Preferred Stock [Member]
Stockholders' Deficit:
Preferred stock	3,275,200	0
HCN Series 7% Convertible Preferred Stock [Member]
Stockholders' Deficit:
Preferred stock	$ 0	$ 1,690,000

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Notes Payable (Details) (USD $)	1 Months Ended			12 Months Ended		1 Months Ended				3 Months Ended
	Sep. 30, 2012	May 31, 2012 Payment	Mar. 17, 2011	Jul. 31, 2014	Jul. 31, 2013	Jun. 30, 2013	Feb. 28, 2014 Payment	Mar. 31, 2013	Oct. 31, 2012	Oct. 31, 2013	Dec. 09, 2013	Sep. 06, 2012	Aug. 31, 2014
Debt Instrument [Line Items]
Consulting fee	$ 2,400,000
Working interest rights (in hundredths)				90.00%							39.00%
Debt instrument, face amount		18,375
Periodic installments amount		567
Debt instrument, interest rate (in hundredths)		6.93%
Variable interest rate (in hundredths)			1.00%
Interest				21,497	207,269
Line of credit facility, amount outstanding			5,000,000
Number of required periodic payments		36
Maturities of long term debt obligation [Abstract]
2015				334,688
Thereafter				0
Total				334,688
Prime Rate [Member]
Debt Instrument [Line Items]
Variable interest rate						prime + 1%
Commercial Insurance Program Renewal [Member]
Debt Instrument [Line Items]
Principal balance				0
Notes Payable For Vehicle Purchase [Member]
Debt Instrument [Line Items]
Principal balance				5,530	11,678
Note Payable For Commercial Insurance Program [Member]
Debt Instrument [Line Items]
Debt instrument, face amount							403,104	260,905
Periodic installments amount							45,718	29,591
Principal balance							179,158
Number of required periodic payments							9
Note Payable - Hydrocarb Corporation [Member]
Debt Instrument [Line Items]
Debt instrument, face amount	1,600,000
Debt instrument, interest rate (in hundredths)	5.00%
Rate of late fee (in hundredths)									10.00%
Period of commencing late fees									30 days
Interest and late fees on notes payable										553,630
Interest										25,000
Note Payable - Hydrocarb Corporation - Payment One [Member]
Debt Instrument [Line Items]
Partial consulting fee payment												800,000
Number of days to the assignment of working interest	15 days
Working interest rights (in hundredths)												39.00%
Periodic installments amount	800,000
Note Payable - Hydrocarb Corporation - Payment Two [Member]
Debt Instrument [Line Items]
Periodic installments amount	800,000
Operating and capital leases [Member]
Maturities of long term debt obligation [Abstract]
2015				0
Thereafter				0
Total				0
Line of Credit [Member]
Debt Instrument [Line Items]
Periodic installments amount						12,500
Debt instrument, interest rate (in hundredths)						6.00%
Variable interest rate (in hundredths)						1.00%
Principal balance				150,000	275,000
Line of credit facility, amount outstanding						300,000
Number of required periodic payments						24
Line of Credit [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Principal balance													150,000
Notes Payable [Member]
Maturities of long term debt obligation [Abstract]
2015				334,688
Thereafter				0
Total				334,688
Term Loan [Member]
Debt Instrument [Line Items]
Amount incurred of late fees				$ 663
Maturity date of term loan				Jun. 22, 2015

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (6,554,849)	$ (37,534,216)
Adjustments to reconcile net income loss to net cash used in operating activities:
Depreciation, depletion, and amortization	910,837	1,121,018
Accretion	1,043,928	1,056,508
(Gain) loss on sale of available for sale securities	0	517,920
Impairment of available for sale securities	0	275,327
Loss on disposal of assets	23,990	14,054
Change in allowance for doubtful accounts	11,948	57,491
Warrants granted to related party	6,754	196,384
Share based compensation	1,757,399	933,126
Acquisition-related costs - related party	0	34,834,752
Gain on derivative warrant liability	0	(1,056,224)
Changes in operating assets and liabilities:
Accounts receivable	353,571	168,096
Other receivables	262,594	0
Accounts receivable - related party	143,270	(68,620)
Other assets	263,510	(89,829)
Accounts payable and accrued expenses	184,900	299,246
Accounts payable related party	1,244,054	125,021
Advances	15,100	125,643
Settlement of asset retirement obligation	(123,664)	(318,225)
NET CASH USED IN OPERATIONS	(456,658)	657,472
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of oil and gas properties	(1,052,679)	(1,564,490)
Purchases of property and equipment	(169,794)	(13,648)
Proceeds from sale of oil and gas properties	625,000	195,563
Change in restricted cash	42,795	(30,739)
Purchase of available for sale securities	0	(24,593)
Proceeds from sale of available for sale securities	0	287,874
CASH USED IN INVESTING ACTIVITIES	(554,678)	(1,150,033)
CASH FLOWS FROM FINANCING ACTIVITIES
Payments on notes payable	(471,052)	(271,972)
Proceeds from note payable to related party	600,000	0
Proceeds from collections on receivable for stock sale	675,000	0
Proceeds from HCN issuance of common stock	31,071	0
Dividend on HCN preferred stock	(34,254)	(69,920)
CASH PROVIDED BY FINANCING ACTIVITIES	800,765	(341,892)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(210,571)	(834,453)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	354,829	1,189,282
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 144,258	$ 354,829

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Additional Financial Statement Information (Schedule of Other Current Assets) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Additional Financial Statement Information [Abstract]
Prepaid letter of credit fees	$ 92,763	$ 93,362
Prepaid insurance	287,743	184,138
Other prepaid expenses	63,143	11,101
Cash call paid to operator	0	24,225
Prepaid land use fees	0	28,728
Accrued interest income	2,671	4,388
Total other current assets	446,320	345,942
Other receivables, allowance for doubtful accounts	$ 70,742	$ 58,585

XML

Supplemental Oil and Gas Information (Unaudited) (Tables)

12 Months Ended

Jul. 31, 2014

Supplemental Oil And Gas Information Unaudited [Abstract]

Schedule of Net Proved Reserves

The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers. Our proved reserves are located in the United States of America, our home country.

Proved Reserves

	Oil			Gas			Total
	(Barrels)			(Mcf)			(Mcfe)
Balance – July 31, 2012		1,388,250			14,737,960			23,067,460
Revisions of previous estimates		(667,307	)		(1,830,745	)		(5,834,587	)
Sale of reserves in place		(1	)		(2	)		(8	)
Production		(61,242	)		(176,823	)		(544,275	)
Balance – July 31, 2013		659,700			12,730,390			16,688,590
Revisions of previous estimates		422,261			4,477			2,538,043
Sale of reserves in place		(17,750	)		(529,937	)		(636,437	)
Production		(42,436	)		(173,569	)		(428,185	)
Balance – July 31, 2014		1,021,775			12,031,361			18,162,011

During the year ended July 31, 2013, the Company decreased estimated reserves reported under the line items “Revisions of previous estimates” due to the decrease of previously estimated reserves related to the wells located in the Fishers Reef field located in Galveston Bay, Texas. As a result, during the year ended July 31, 2013, the Company plugged and abandoned these wells. During the year ended July 31, 2014, the Company increased estimated reserves reported under the line items “Revisions of previous estimates” due to an increase in certain previously estimated reserves in the Galveston Bay, Texas properties. When we acquired Galveston Bay Energy LLC in 2011, the Company had over 100 well-bores that had been shut in and scheduled for potential plugging and abandonment. Since the date of the acquisition, our technical staff undertook a review of the old well logs and other technical data associated with such review to identify additional undeveloped oil reserves in these leases. All increases in proved undeveloped reserves are due to the re-evaluation of previously available technical data associated with such review. We have not obtained new technical data. We believe that the new interpretations and reevaluations better reflect the underlying technical data. For the year ended July 31, 2014, this increase related primarily to revaluations associated with the Trinity Bay Field.

	Oil		Gas		Total
Proved Reserves as of July 31, 2014	(Barrels)		(Mcf)		(Mcfe)
Proved developed producing		200,981		969,940		2,175,826
Proved developed non-producing		212,320		4,813,192		6,087,112
Proved undeveloped		608,474		6,248,229		9,899,073
Total proved reserves		1,021,775		12,031,361		18,162,011

	Oil		Gas		Total
Proved Reserves as of July 31, 2013	(Barrels)		(Mcf)		(Mcfe)
Proved developed producing		256,290		1,554,420		3,092,160
Proved developed non-producing		229,290		5,000,960		6,376,700
Proved undeveloped		174,120		6,175,010		7,219,730
Total proved reserves		659,700		12,730,390		16,688,590

Schedule of Capitalized Costs

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization.

For the year ended July 31,	2014			2013
Unevaluated properties	$	2,119,769		$	713,655
Evaluated properties		19,153,124			19,857,842
Less impairment		(373,335	)		(373,335	)
		20,899,558			20,609,312
Less depreciation, depletion, and amortization		(3,491,420	)		(2,617,478	)
Net capitalized cost	$	17,408,139		$	17,580,684

Schedule of Costs Incurred

Costs incurred in property acquisition, exploration and development activities for the year ended July 31, 2014 were as follows.

	Total			Namibia		USA
Property acquisition
Unproved	$	1,232,815		$	1,232,815	$	-
Proved		13			-		13
Exploration		238,112			173,299		64,813
Development		-			-		-
Cost recovery		(658,195	)		-		(658,195	)
Total costs incurred	$	812,745		$	1,406,114	$	(593,369	)

Costs incurred in property acquisition, exploration, and development activities for the year ended July 31, 2013 were all incurred in the USA.  The following table provides information about the costs incurred:

	Total			Namibia		USA
Property acquisition
Unproved	$	808,307		$	677,795	$	130,512
Proved		3,000			-		3,000
Exploration		404,265			35,860		368,405
Development		1,732,451			-		1,732,451
Cost recovery		(196,001	)		-		(196,001	)
Total costs incurred	$	2,752,022		$	713,655	$	2,038,367

Schedule of Costs Excluded by Year

Costs Excluded by Year Incurred

As of July 31,	2014		2013
Property acquisition	$	1,232,815	$	677,795
Exploration		173,299		35,860
Total	$	1,406,114	$	713,655

Schedule of Costs Excluded by Country

Changes in Costs Excluded by Country

	Namibia		USA
Balance at July 31, 2012	$	-	$	265,639
Additional Cost Incurred		713,655		278,090
Cost recovery		-		(132,662	)
Costs Transferred to DD&A Pool		-		(411,067	)
Balance at July 31, 2013		713,655		-
Additional Cost Incurred		1,406,114		-
Balance at July 31, 2014	$	2,119,769.00	$	-

Schedule of Standardized Measure

The Standardized Measure is as follows:

For the year ended July 31,	2014			2013
Future cash inflows	$	159,283,690		$	113,603,450
Future production costs		(54,437,098	)		(55,897,070	)
Future development costs		(43,054,816	)		(41,794,284	)
Future income tax expenses		(21,627,122	)		(5,569,234	)
		40,164,654			10,342,862
10% annual discount for estimated timing of cash flows		(15,807,988	)		(3,990,069	)
Future net cash flows at end of year	$	24,356,666		$	6,352,793

Schedule of Changes in Standardized Measure

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for our proved oil and natural gas reserves during each of the years in the two year period ended July 31, 2014:

	2014			2013
Standardized measure of discounted future net cash flows at beginning of year	$	6,352,793		$	33,663,886
Net changes in prices and production costs		20,980,014			(37,623,010	)
Changes in estimated future development costs		(764,412	)		4,205,045
Sales of oil and gas produced, net of production costs		(151,783	)		(2,510,339	)
Discoveries and extensions		-			-
Purchases of minerals in place		-			-
Sales of minerals in place		(2,228,023	)		(17	)
Revisions of previous quantity estimates		8,885,117			(12,391,911	)
Development costs incurred		-			1,124,107
Change in income taxes		(9,694,393	)		14,705,973
Accretion of discount		977,353			5,179,059
Standardized measure of discounted future net cash flows at year end	$	24,356,666		$	6,352,793

Schedule of Results of Operations for Producing Activities

For the year ended July 31,	2014			2013
Net revenues from production	$	5,065,096		$	7,070,540
Expenses
Lease operating expense		4,913,313			4,560,201
Accretion		1,043,928			1,056,508
Operating expenses		5,957,241			5,616,709
Depreciation, depletion and amortization		873,942			1,059,803
Total expenses		6,831,183			6,676,512
Income before income tax		(1,766,087	)		394,028
Income tax expense		-			(137,910	)
Results of operations	$	(1,766,087	)	$	256,118
Depreciation, depletion and amortization rate per net equivalent MCFE	$	2.04		$	1.95

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Capitalized Costs) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Unevaluated properties	$ 2,119,769	$ 1,124,805
Evaluated properties	19,153,124	19,857,842
Less impairment	(373,335)	(373,335)
Gross capitalized costs	20,899,558	20,609,312
Less depreciation, depletion and amortization	(3,491,420)	(2,617,478)
Net capitalized cost	$ 17,408,139	$ 17,991,834

XML

Supplemental Oil and Gas Information (Unaudited)

12 Months Ended

Jul. 31, 2014

Supplemental Oil And Gas Information Unaudited [Abstract]

Supplemental Oil and Gas Information (Unaudited)

Note 16 – Supplemental Oil and Gas Information (Unaudited)

The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the SEC and ASC 932, Extractive Activities —Oil and Gas, (ASC 932).

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made. The oil price as of July 31, 2014 and 2014 is based on the 12-month un-weighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) posted price which equates to $100.11 and $92.52 per barrel, respectively. The gas price as of July 31, 2014 and 2013 is based on the 12-month un-weighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) spot price which equates to $4.10 and $3.51 per MMbtu, respectively. The base prices were adjusted for heating content, premiums and product differentials based on historical revenue statements. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States; specifically, primarily in on-shore and off-shore Texas.

The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers. Our proved reserves are located in the United States of America, our home country.

Proved Reserves

	Oil			Gas			Total
	(Barrels)			(Mcf)			(Mcfe)
Balance – July 31, 2012		1,388,250			14,737,960			23,067,460
Revisions of previous estimates		(667,307	)		(1,830,745	)		(5,834,587	)
Sale of reserves in place		(1	)		(2	)		(8	)
Production		(61,242	)		(176,823	)		(544,275	)
Balance – July 31, 2013		659,700			12,730,390			16,688,590
Revisions of previous estimates		422,261			4,477			2,538,043
Sale of reserves in place		(17,750	)		(529,937	)		(636,437	)
Production		(42,436	)		(173,569	)		(428,185	)
Balance – July 31, 2014		1,021,775			12,031,361			18,162,011

During the year ended July 31, 2013, the Company decreased estimated reserves reported under the line items “Revisions of previous estimates” due to the decrease of previously estimated reserves related to the wells located in the Fishers Reef field located in Galveston Bay, Texas. As a result, during the year ended July 31, 2013, the Company plugged and abandoned these wells. During the year ended July 31, 2014, the Company increased estimated reserves reported under the line items “Revisions of previous estimates” due to an increase in certain previously estimated reserves in the Galveston Bay, Texas properties. When we acquired Galveston Bay Energy LLC in 2011, the Company had over 100 well-bores that had been shut in and scheduled for potential plugging and abandonment. Since the date of the acquisition, our technical staff undertook a review of the old well logs and other technical data associated with such review to identify additional undeveloped oil reserves in these leases. All increases in proved undeveloped reserves are due to the re-evaluation of previously available technical data associated with such review. We have not obtained new technical data. We believe that the new interpretations and reevaluations better reflect the underlying technical data. For the year ended July 31, 2014, this increase related primarily to revaluations associated with the Trinity Bay Field.

	Oil		Gas		Total
Proved Reserves as of July 31, 2014	(Barrels)		(Mcf)		(Mcfe)
Proved developed producing		200,981		969,940		2,175,826
Proved developed non-producing		212,320		4,813,192		6,087,112
Proved undeveloped		608,474		6,248,229		9,899,073
Total proved reserves		1,021,775		12,031,361		18,162,011

	Oil		Gas		Total
Proved Reserves as of July 31, 2013	(Barrels)		(Mcf)		(Mcfe)
Proved developed producing		256,290		1,554,420		3,092,160
Proved developed non-producing		229,290		5,000,960		6,376,700
Proved undeveloped		174,120		6,175,010		7,219,730
Total proved reserves		659,700		12,730,390		16,688,590

Proved developed producing and proved developed non-producing reserves decreased from July 31, 2014 to July 31, 2013 as a result of changes in estimates, based on current information.  The increase in proved undeveloped reserves was a result of an increase in certain previously estimated reserves in the Galveston Bay, Texas property.

The reserves in the report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.

Capitalized Costs Related to Oil and Gas Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization.

For the year ended July 31,	2014			2013
Unevaluated properties	$	2,119,769		$	713,655
Evaluated properties		19,153,124			19,857,842
Less impairment		(373,335	)		(373,335	)
		20,899,558			20,609,312
Less depreciation, depletion, and amortization		(3,491,420	)		(2,617,478	)
Net capitalized cost	$	17,408,139		$	17,580,684

Costs Incurred in Oil and Gas Activities

Costs incurred in property acquisition, exploration and development activities for the year ended July 31, 2014 were as follows.

	Total			Namibia		USA
Property acquisition
Unproved	$	1,232,815		$	1,232,815	$	-
Proved		13			-		13
Exploration		238,112			173,299		64,813
Development		-			-		-
Cost recovery		(658,195	)		-		(658,195	)
Total costs incurred	$	812,745		$	1,406,114	$	(593,369	)

Costs incurred in property acquisition, exploration, and development activities for the year ended July 31, 2013 were all incurred in the USA.  The following table provides information about the costs incurred:

	Total			Namibia		USA
Property acquisition
Unproved	$	808,307		$	677,795	$	130,512
Proved		3,000			-		3,000
Exploration		404,265			35,860		368,405
Development		1,732,451			-		1,732,451
Cost recovery		(196,001	)		-		(196,001	)
Total costs incurred	$	2,752,022		$	713,655	$	2,038,367

Costs Excluded

Our excluded costs as of July 31, 2014 and 2013 relate to costs incurred in the concession acquired in Namibia, Africa. The concession provides for a multi-year exploration program as described in Note 4 – Oil and Gas Properties.  The program provides that an initial well be drilled by September 2017.  Accordingly, we anticipate including the excluded costs in the amortization base within the next four to five years.  All costs that were excluded as of July 31, 2014 and 2013 were as follows, and were incurred during the respective years noted below.

Costs Excluded by Year Incurred

As of July 31,	2014		2013
Property acquisition	$	1,232,815	$	677,795
Exploration		173,299		35,860
Total	$	1,406,114	$	713,655

Costs excluded as of July 31, 2013 consisted of acquisition and drilling costs associated with a project onshore in Texas, the Chapman Ranch prospect.  During the year ended July 31, 2013, we incurred additional acquisition and exploration costs for this project as well as other projects onshore in Texas.  All such costs were classified as evaluated as of July 31, 2013 because they were not successful in discovering oil and gas reserves.

Changes in Costs Excluded by Country

	Namibia		USA
Balance at July 31, 2012	$	-	$	265,639
Additional Cost Incurred		713,655		278,090
Cost recovery		-		(132,662	)
Costs Transferred to DD&A Pool		-		(411,067	)
Balance at July 31, 2013		713,655		-
Additional Cost Incurred		1,406,114		-
Balance at July 31, 2014	$	2,119,769.00	$	-

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flow information has been developed utilizing ASC 932, Extractive Activities —Oil and Gas, (ASC 932) procedures and based on estimated oil and natural gas reserve and production volumes. It can be used for some comparisons, but should not be the only method used to evaluate us or our performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of our current value.

We believe that the following factors should be taken into account when reviewing the following information:

● future costs and selling prices will probably differ from those required to be used in these calculations;

● due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

● a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

● future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, the future cash inflows were estimated by applying the un-weighted 12-month average of the first day of the month cash price quotes, except for volumes subject to fixed price contracts, to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.  All proved reserves are located in the United States of America.

The Standardized Measure is as follows:

For the year ended July 31,	2014			2013
Future cash inflows	$	159,283,690		$	113,603,450
Future production costs		(54,437,098	)		(55,897,070	)
Future development costs		(43,054,816	)		(41,794,284	)
Future income tax expenses		(21,627,122	)		(5,569,234	)
		40,164,654			10,342,862
10% annual discount for estimated timing of cash flows		(15,807,988	)		(3,990,069	)
Future net cash flows at end of year	$	24,356,666		$	6,352,793

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for our proved oil and natural gas reserves during each of the years in the two year period ended July 31, 2014:

	2014			2013
Standardized measure of discounted future net cash flows at beginning of year	$	6,352,793		$	33,663,886
Net changes in prices and production costs		20,980,014			(37,623,010	)
Changes in estimated future development costs		(764,412	)		4,205,045
Sales of oil and gas produced, net of production costs		(151,783	)		(2,510,339	)
Discoveries and extensions		-			-
Purchases of minerals in place		-			-
Sales of minerals in place		(2,228,023	)		(17	)
Revisions of previous quantity estimates		8,885,117			(12,391,911	)
Development costs incurred		-			1,124,107
Change in income taxes		(9,694,393	)		14,705,973
Accretion of discount		977,353			5,179,059
Standardized measure of discounted future net cash flows at year end	$	24,356,666		$	6,352,793

The following schedule includes only the revenues from the production and sale of gas, oil, condensate and NGLs. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

Results of Operations for Producing Activities

For the year ended July 31,	2014			2013
Net revenues from production	$	5,065,096		$	7,070,540
Expenses
Lease operating expense		4,913,313			4,560,201
Accretion		1,043,928			1,056,508
Operating expenses		5,957,241			5,616,709
Depreciation, depletion and amortization		873,942			1,059,803
Total expenses		6,831,183			6,676,512
Income before income tax		(1,766,087	)		394,028
Income tax expense		-			(137,910	)
Results of operations	$	(1,766,087	)	$	256,118
Depreciation, depletion and amortization rate per net equivalent MCFE	$	2.04		$	1.95

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Description of Business and Summary of Significant Accounting Policies (Details) (USD $)	0 Months Ended	12 Months Ended		0 Months Ended
	May 08, 2014	Jul. 31, 2014 Partner	Jul. 31, 2013	Apr. 04, 2012	May 08, 2014	Dec. 09, 2013	Nov. 29, 2013	Jul. 19, 2005	Oct. 18, 2005	May 16, 2012
Subsidiary or Equity Method Investee [Line Items]
Common stock, shares authorized (in shares)		333,333,333	333,333,333				166,666,667
Common stock par value per share		$ 0.001	0.001				$ 0.001
Reverse stock split conversion ratio	3
Working interest rights (in hundredths)		90.00%				39.00%
Cost responsibility rate (in hundredths)		100.00%
Revenue, Major Customer [Line Items]
Number of working interest partners		2
Other receivables, allowance for doubtful accounts		$ 70,742	58,585
Discount percentage on current prices (in hundredths)		10.00%
Restricted cash		6,877,944	6,920,739
Prepaid land use fees, term		10 years
Purchase of domain name		30,267
Advances		$ 195,904	180,804
Reverse stock split	1:3 reverse split
Minimum [Member]
Revenue, Major Customer [Line Items]
Approximate Life		3 years
Maximum [Member]
Revenue, Major Customer [Line Items]
Approximate Life		5 years
Purchaser One [Member] | Revenues [Member]
Revenue, Major Customer [Line Items]
Risk percentage (in hundredths)		83.00%	85.00%
Purchaser One [Member] | Accounts receivable [Member]
Revenue, Major Customer [Line Items]
Risk percentage (in hundredths)		88.00%	76.00%
Penasco Petroleum Inc [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Galveston Bay, LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Number of offshore fields having working interest		4
SPE Navigation I, LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Namibia Exploration, Inc [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Cost responsibility rate (in hundredths)		100.00%
Nevada Gold Corp [Member]
Subsidiary or Equity Method Investee [Line Items]
Common stock, shares authorized (in shares)								100,000,000
Gulf States Energy, Inc [Member]
Subsidiary or Equity Method Investee [Line Items]
Common stock, shares authorized (in shares)									500,000,000
Common stock par value per share									$ 0.001
Duma Energy Corp [Member]
Subsidiary or Equity Method Investee [Line Items]
Common stock, shares authorized (in shares)				20,000,000			1,000,000,000			500,000,000
Reverse stock split conversion ratio				25
Hydrocarb Energy Corp [Member]
Subsidiary or Equity Method Investee [Line Items]
Common stock, shares authorized (in shares)		333,333,333
Common stock par value per share		$ 0.001
Reverse stock split conversion ratio					3
Hydrocarb Corporation, HCN [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Working interest rights (in hundredths)						51.00%
Hydrocarb Texas Corporation [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Hydrocarb Namibia Energy [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Otaiba Hydrocarb LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		95.00%

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Acquisitions (Tables)

12 Months Ended

Jul. 31, 2014

Acquisitions [Abstract]

Summary of Pro Forma Information

Summary of the accounting entry to record this acquisition in December 2013 is as follows:

Assets acquired	$	1,529,246
Liabilities assumed		(161,599	)
Noncontrolling interest in 95% owned HCN subsidiary		30,480
	$	1,398,127
Series A 7% Preferred Stock, par $400	$	3,275,200
Common stock, at par		8,397
Receivable for common stock		(2,484,879	)
Additional paid-in capital		599,409
	$	1,398,127

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Costs Excluded by Country) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Ending Balance	$ 1,406,114	$ 713,655
Namibia [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Beginning Balance	713,655	0
Additional Cost Incurred	1,406,114	713,655
Cost Recovery		0
Costs Transferred to DD&A Pool		0
Ending Balance	2,119,769	713,655
Unites States [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Beginning Balance	0	265,639
Additional Cost Incurred	0	278,090
Cost Recovery		(132,662)
Costs Transferred to DD&A Pool		(411,067)
Ending Balance	$ 0	$ 0

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Description of Business and Summary of Significant Accounting Policies

12 Months Ended

Jul. 31, 2014

Description of Business and Summary of Significant Accounting Policies [Abstract]

Description of Business and Summary of Significant Accounting Policies

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

Description of business and basis of presentation

We are a natural resource exploration and production company engaged in the exploration, acquisition, development, and production of oil and gas properties in the United States and onshore in Namibia, Africa.  We were incorporated under the laws of the State of Nevada on April 12, 2005 under the name “Carlin Gold Corporation”. On July 19, 2005, we changed our name to “Nevada Gold Corp.” On October 18, 2005, we changed our name to “Gulf States Energy, Inc.” and increased our authorized capital from 100,000,000 shares of common stock to 500,000,000 shares of common stock, par value $0.001 per share. On September 5, 2006, we changed our name to “Strategic American Oil Corporation”.  On April 4, 2012 we completed a one new share for twenty-five old share (1:25) reverse stock split and as a result our authorized capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock.  Also, effective April 4, 2012, we changed our name to “Duma Energy Corp.”  Effective May 16, 2012, we increased our authorized capital from 20,000,000 shares to 500,000,000 shares of common stock.  Effective November 29, 2013, the Company increased the number of its authorized shares of common stock from 500,000,000 to 1,000,000,000 shares of common stock.    Effective February 18, 2014, we changed our name from Duma Energy Corp. to Hydrocarb Energy Corp.  Effective May 8, 2014, we effected a 1:3 reverse split of our authorized common stock and a corresponding 1:3 reverse split of our outstanding common stock.  All share and per share amounts for all periods in this report have been retroactively restated to reflect the reverse split. Our capitalization at July 31, 2014 was 333,333,334 authorized common shares with a par value of $0.001 per share.  Our common stock is quoted under the symbol “HECC” on the OTCBB.

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.

We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas limited liability company, (iii) SPE Navigation I, LLC, a Nevada limited liability company, (iv) Namibia Exploration, Inc., a Nevada corporation, (v) Hydrocarb Corporation, a Nevada corporation, (vi) Hydrocarb Texas Corporation, a Texas corporation, and (vii) Hydrocarb Namibia Energy (Pty) Limited, a company chartered in the Republic of Namibia.  In addition, we own 95% of the issued and outstanding share capital of Otaiba Hydrocarb LLC, a UAE limited liability corporation.

As of July 31, 2014, we maintain developed and undeveloped acreage offshore in Texas.  As of July 31, 2014, we were producing oil and gas from our working interest in four offshore fields in Galveston Bay, Texas.  During September 2012, we acquired, through the acquisition of Namibia Exploration Inc., a 39% non-operated working interest in a concession located onshore in Namibia, Africa.  During December 2013, with our acquisition of Hydrocarb Corporation, we acquired 51% working interest in this onshore Namibia, Africa concession and now own 90% working interest (100% cost responsibility) in the Namibia, Africa concession.

Reclassifications

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

Principles of consolidation

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 accompanying consolidated financial statements include the accounts of Hydrocarb Energy Corp., our wholly owned subsidiaries Penasco Petroleum Corporation (“Penasco”), SPE Navigation I, LLC (“SPE”), Galveston Bay Energy, LLC (“GBE”), Namibia Exploration, Inc. (“NEI”), Hydrocarb Corporation (“HCN”), Hydrocarb Texas Corporation, and Hydrocarb Namibia Energy (Pty) Limited.  In addition, these financials include our 95% ownership interest in Otaiba Hydrocarb LLC.  All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

Significant areas requiring management’s estimates and assumptions include the determination of the fair value of transactions involving stock-based compensation and financial instruments, estimates of the costs and timing of asset retirement obligations, and oil and natural gas proved reserve quantities.  Oil and natural gas proved reserve quantities form the basis for the calculation of amortization of oil and natural gas properties and for asset impairment tests. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories.

Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.

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.

Receivables and allowance for doubtful accounts

Oil and gas revenues receivable are recorded at the invoiced amount and do not bear any interest. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Management has determined that a reserve for uncollectible amounts was not required in the periods presented.

Accounts receivable – related party includes the oil and gas revenue receivable from our Barge Canal properties, which, up until September 1, 2013, were operated by a company owned by one of our former officers who was also a director, and joint interest billings receivable from two working interest partners who are related to our former Chief Financial Officer, the former Chief Executive Officer and the current Chief Executive Officer. This balance also includes an oil and gas receivable from Lifestream, LLC, a company owned by the brother of our current CEO.

Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate.

We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.  As of July 31, 2014 and 2013, we have reserved $70,742 and $58,585, respectively, for potentially uncollectable other receivables.

Available for sale securities

We invest in marketable equity securities which are classified as available for sale. The first in first out method is used to determine the cost basis of our equity securities sold. Available-for-sale securities are marked to market based on the fair values of the securities determined in accordance with ASC Section 820 (Fair Value Measurement), with the unrealized gains and losses, net of tax, reported as a component of accumulated other comprehensive income (loss).

Other current assets

Other current assets consist primarily of prepaid insurance, prepaid interest expense, prepayments made towards properties not operated by us, and accrued interest on our deposits.

Concentrations

Our operations are concentrated in Texas and the majority of our operations are conducted offshore in Galveston Bay.  We operate in the oil and gas exploration and production industry. If the oil and natural gas exploration and production industry as a whole were adversely affected, for example by weather, supply shortages, or other factors, we would also experience adverse effects. Because our properties are offshore, we are also vulnerable to adverse weather.

For the year ended July 31, 2014, 83% of our revenue was attributable to one purchaser.  At July 31, 2014, this same purchaser accounted for 88% of our accounts receivable. For the year ended July 31, 2013, 85% of our revenue was attributable to one purchaser.  At July 31, 2013, this same purchaser accounted for 76% of our accounts receivable.

We place cash with high quality financial institutions and at times may exceed the federally insured limits. We have not experienced a loss in such accounts nor do we expect any related losses in the near term.

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.

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 unit 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.

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.

Impairment

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 proved 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.  During the years ended July 31, 2014 and July 31, 2013, the ceiling exceeded the net book value of the property and it was not necessary to record an impairment charge.

Asset retirement obligation

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 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 update our assessment accordingly. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gathering systems as these obligations are incurred.

Restricted cash

Restricted cash consists of certificates of deposit that have been posted as collateral for letters of credit supporting bonds guaranteeing remediation of our oil and gas properties in Texas and escrow funds deposited directly with regulatory authorities. As of July 31, 2014 and 2013, restricted cash totaled $6,877,944 and $6,920,739, respectively.

Other assets

Other assets at July 31, 2014 and 2013 consisted primarily of prepaid land use fees, which are payments that cover multiple years (typically ten years) rental for easements and surface leases.  These are paid as they come due on an ongoing basis and amortized over the rental period.  In addition, other assets also include a domain name for $30,267, which is an intangible asset with an indefinite life due to the fact that it is renewable annually for nominal cost.  We evaluate intangible assets with an indefinite life for possible impairment at least annually by comparing the fair value of the asset with its carrying value.

Property and equipment, other than oil and gas

Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally three to five years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. We perform ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.

Impairment of long-lived assets

We periodically review our long-lived assets, other than oil and gas property, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. We recognize an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value. We recorded no impairment on our non-oil and gas long-lived assets during the years ended July 31, 2014 and 2013, respectively.

Advances

Advances consist of prepayments received from working interest partners pertaining to their share of the costs of drilling oil and gas wells.  Partners are billed in advance for the estimated cost to drill a well and as the work proceeds, the prepayment is applied against their share of the actual drilling cost.  As of July 31, 2014 and 2013, advances totaled $195,904 and $180,804, respectively.

Revenue recognition

We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. Actual sales of gas are based on sales, net of the associated volume charges for processing fees and for costs associated with delivery, transportation, marketing, and royalties in accordance with industry standards. Operating costs and taxes are recognized in the same period in which revenue is earned.  Severance and ad valorem taxes are reflected as a component of lease operating expense.

Income taxes

We account for income taxes using the asset and liability method. Under this method, deferred income tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Fair value

Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.

Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.

The three-level hierarchy is as follows:

● Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.

● Level 2 inputs consist of quoted prices for similar instruments.

● Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  We have determined that certain warrants outstanding during the period covered by these financial statements qualify as derivative financial instruments under the provisions of FASB ASC Topic No. 815-40, “Derivatives and Hedging – Contracts in an Entity’s Own Stock.” (See Note 8 – Fair Value).

The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain on derivative warrant liability.”

Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.

We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2014 or July 31, 2013. The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable – related party, accounts payable and accrued expenses, and notes payable approximate their fair market value based on the short-term maturity of these instruments.

Stock-based compensation

ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.

We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.”  ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete.  Generally, our awards do not entail performance commitments.  When an award vests over time such that performance occurs over multiple reporting periods, 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 vesting date, which is presumed to be the date performance is complete.

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.

Stock Split

On May 8, 2014, we affected a 1-for-3 reverse stock split.  All share and per share amounts 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 or the effective date of the registration statement, whichever is later.

Earnings per share

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share includes the dilutive effects of common stock equivalents on an “as if converted” basis. For the years ended July 31, 2014 and 2013, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.

Contingencies

Legal

We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.  See Note 13 - Commitments and Contingencies for more information on legal proceedings.

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.

Accumulated Other Comprehensive Income (Loss), net of tax

We follow the provisions of ASC 220, "Comprehensive Income", which establishes standards for reporting comprehensive income. In addition to net loss, comprehensive loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company.

Recent accounting pronouncements

In March 2013, the FASB amended ACS 830, Foreign Currency Matters, to clarify the appropriate accounting when a parent ceases to have a controlling interest in a subsidiary or group of assets that is a business within a foreign entity. This clarification provides that the cumulative translation adjustment should only be released into net income if the loss of controlling interest represents complete or substantially complete liquidation of the foreign entity in which the subsidiary or asset group had resided. This amendment is effective for us starting with our first quarter of fiscal year 2015 and adoption would impact our consolidated financial condition and results of operations if we dispose of a foreign entity.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (“ASU No. 2014-09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance when it becomes effective. This new standard is effective for us starting with our first quarter of fiscal year 2018.  Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

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.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Accumulated depletion on evaluated oil and gas property accounted for using the full cost method of accounting	$ 3,491,420	$ 2,617,478
Accumulated impairment on evaluated oil and gas property accounted for using the full cost method of accounting	373,355	373,355
Accumulated depreciation recorded for property and equipment	$ 135,590	$ 116,945
Equity [Abstract]
Preferred stock, shares issued (in shares)	4,225
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	333,333,333	333,333,333
Common stock, shares issued (in shares)	21,081,602	4,427,071
Common stock, shares outstanding (in shares)	21,081,602	4,427,071
Series A 7% Convertible Preferred Stock [Member]
Equity [Abstract]
Preferred Stock, par value (in dollars per share)	$ 400	$ 400
Preferred stock, shares authorized (in shares)	10,000
Preferred stock, shares issued (in shares)	8,188
Preferred stock, shares outstanding (in shares)	8,188
HCN Series 7% Convertible Preferred Stock [Member]
Equity [Abstract]
Preferred Stock, par value (in dollars per share)	$ 400	$ 400

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Related Party Transactions

12 Months Ended

Jul. 31, 2014

Related Party Transactions [Abstract]

Related Party Transactions

Note 11 – Related Party Transactions

During the year ended July 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 Barge Canal properties. Although he was not a related party after September 2013, we considered the transactions with his company during his tenure as an officer of Hydrocarb as related party transactions because they were not compensation or ordinary course of business, and because he was a related party at the time they occurred.

Revenues generated, lease operating costs, and contractual overhead charges, which are included in lease operating costs incurred from these properties, were as follows:

Year Ended July 31,	2013		2014
Revenue generated from Barge Canal properties	$	643,203	$	39,274
Lease operating cost incurred from Barge Canal properties	$	224,047	$	23,259
Overhead costs incurred	$	28,038	$	-
Outstanding accounts receivable at period end	$	91,967	$	-
Outstanding accounts payable at year end	$	-	$	-

During the quarter ended October 2012, we purchased NEI for up to  8,396,667 shares of Duma common stock, as described in Note 2 – Acquisitions – Namibia Exploration, Inc.

In February 2013, we sold a 2% working interest in a 366.85 acre tract of unevaluated property, the Dix prospect, in San Patricio County, Texas to Carter. Carter paid cash of $1,541, the proportional share of the land acquisition costs.

In August 2013, we closed our Corpus Christi office and terminated this officer.  In conjunction with the office closure and termination, we assumed operatorship of the Barge Canal properties effective September 1, 2013.  In addition, we conveyed multiple properties located in the South Texas and Illinois area to this officer for $0 cash consideration and assumption of the associated asset retirement obligations. (See Note 5– Oil and Gas Properties)

The father of the former Chief Financial Officer and a company controlled by the father-in-law of the former Chief Executive Officer and brother to the current CEO, each purchased a 5% working interest in the ST 9-12A #4 well.  As of July 31, 2014 and 2013, the company controlled by the father-in-law of the former Chief Executive Officer owed us $58,014 and  $84,806, respectively. We also had an advance outstanding from the father of the former Chief Financial Officer, which was reflected in the caption “Due to related parties”, of $0 and $15,046 for the year ended July 31, 2014 and 2013, respectively.

During 2011, we entered into a consulting contract with a company controlled by Michael Watts, the father-in-law of Jeremy Driver, our former Chief Executive Officer and a former Director and the brother of our current CEO, as detailed in Note 10 – Capital Stock.  We recognized expense of $196,384 from this contract during the year ended July 31, 2013.  The contract terminated in 2014 but was extended by the board of directors indefinitely with zero additional compensation.  $6,754 was recognized in the year ended July 31, 2014.

In September 2013, before the HEC acquisition of HCN, HCN sold 191,667 shares of HEC common stock to an HCN employee, our Chairman’s nephew, in exchange for a $1,000,000 note receivable. The company arranged the sales of these shares in anticipation of a possible business combination, in an effort to ensure that the shares would remain as part of public float and therefore continue to be properly included in calculations for exchange-listing criteria and provide a source of funding for company operations. It was anticipated that the purchaser of these shares would, at a subsequent date, sell the referenced shares and attain the ability to pay the receivable. We collected $675,000 on the referenced note receivable through April 30, 2014. Of that amount, $275,000 was derived from the sales of the referenced shares; $400,000 was derived from the proceeds of a loan made to the purchaser of the referenced shares by our Chairman.

In October 2013, prior to our acquisition of HCN, we settled our obligations to HCN under the HCN Consulting Agreement through the issuance of 619,960 shares of HEC. These obligations consisted of the then-outstanding $2,400,000 Fee and $533,630 of interest and late fees associated with the Fee. (See Note 10 – Capital Stock). Further, $25,000 of the related interest and fees was settled in cash. Prior to HEC’s acquisition of HCN, HCN sold these shares to an unrelated entity, in which Michael Watts has a minority interest, for a note receivable of $1,859,879. The company arranged the sales of these shares in anticipation of a possible business combination, in an effort to ensure that the shares would remain as part of public float and therefore continue to be properly included in calculations for exchange-listing criteria and provide a source of funding for company operations. It is anticipated that these shares will eventually be sold and the proceeds of their sales used to pay the receivable. As HCN is now our wholly-owned subsidiary, this receivable for the sale of HEC common stock is classified as receivable for common stock within equity. See discussion of this receivable in Note 10 – Capital Stock – Receivables for Common Stock. On August 8, 2014 our board of Directors resolved to extend this note receivable with [                ] $750,000 to be paid by December 31, 2014 and the balance by March 31, 2015.

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. Additonally, 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 July 31, 2014. Accrued interest is pavable 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.

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Document and Entity Information (USD $)	12 Months Ended
	Jul. 31, 2014	Oct. 22, 2014	Jan. 31, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	HYDROCARB ENERGY CORP
Entity Central Index Key	0001425808
Current Fiscal Year End Date	--07-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 22,570,168
Entity Common Stock, Shares Outstanding		21,186,602
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	true
Amendment Description	On November 13, 2014, Hydrocarb Energy Corporation (the “Company”) filed its Annual Report on Form 10-K for its fiscal year ended July 31, 2014 (the “Original Form 10-K”). Subsequent to the filing of the Original Form 10-K, the Company became aware of various issues (described in greater detail below) relating to such filing and, the Company is hereby amending its Original Form 10-K. Revisions to the Original Form 10-K are made in the following areas. Revisions to the Original Form 10-K are made in Items 1, 7, 8 and 15. In Note 15 – Subsequent Events, added language relating to termination of oil and gas activities in the U.A.E. In Note 16 - Supplemental Oil and Gas Information (Unaudited), expanded disclosure related to reasons and circumstances for changes in “Revisions of previous estimates” for the years ended July 31, 2014 and 2013, respectively. Also expanded disclosure to explain differences between total proved undiscounted future net income shown in the reserve report and the disclosure in Note 16 of future cash inflows less the future production and future development costs for each of the periods ending July 31, 2014 and 2013, respectively.
Document Period End Date	Jul. 31, 2014

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Income Taxes

12 Months Ended

Jul. 31, 2014

Income Taxes [Abstract]

Income Taxes

Note 12- Income Taxes

Our net loss before income taxes totaled $(7,683,932) and $(37,595,653) for the years ended July 31, 2014 and 2013, respectively. We recognized an income tax benefit during the years ended July 31. 2014 and 2013 because the estimated tax liability for the respective previous years exceeded the actual tax liability.

The reconciliation of our income tax provision at the statutory rate to the reported income tax expense is as follows:

As of and For the Year ended July 31,	2014			2013
U.S statutory federal rate		35 00	%		35.00	%
State income tax rate		0.58	%		0.58	%
Equity-based compensation		(5.16	)%		(33.62	)%
Gain on derivative warrants		-	%		0.93	%
Gain on sale of securities		-	%		(0.33	)%
Other		(6.64	)%		(0.50	)%
Net operating loss		(23.70	)%		(1.75	)%
Effective statutory rate		0.08	%		0.31	%

Our deferred income taxes reflect the net tax effects of operating loss, tax credit carry forwards and temporary differences between carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which temporary differences representing net future deductible amounts become deductible.

Components of deferred tax assets as of July 31, 2014 and 2013 are as follows:

As of and For the Year ended July 31.	2014			2013
Stock based compensation	$	338,078		$	713,867
Property. including depreciable property		(3,122,873	)		(2,980,005	)
Asset retirement obligation		4,168,049			3,942,918
Net operating loss carry-forward		5,596,732			3,846,783
Other		20,860			42,368
		7,000,846			5,565,931
Valuation allowance for deferred tax assets		(7,000,846	)		(5,565.931	)
Total deferred tax assets	$	-		$	-

The valuation allowance is evaluated at the end of each year, considering positive and negative evidence about whether the deferred tax asset will be realized. At that time, the allowance will either be increased or reduced; reduction could result in the complete elimination of the allowance if positive evidence indicates that the value of the deferred tax assets is no longer impaired and the allowance is no longer required.

We have no positions for which it is reasonable that the total amounts of unrecognized tax benefits at July 31. 2014 will significantly increase or decrease within 12 months.

Generally, our income tax years 2010 through 2014 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas which are the jurisdictions where we have our principal operations. No material amounts of the unrecognized income tax benefits have been identified to date that would impact our effective income tax rate.

As of July 31, 2014, we had approximately $15,732,204 of U.S. federal and state net operating loss carry-forward (“NOLs”) available to offset future taxable income, which begins expiring in 2027, if not utilized. Future tax benefits that may arise as a result of these losses have not been recognized in these financial statements.  The deferred tax asset generated by the loss carry-forward has been fully reserved due to the uncertainty we will be able to realize the benefit from it.

In conjunction with the merger with HCN, we believe we incurred an ownership change within the meaning of Section 382 of the Internal Revenue Code. As a result, applicable federal and state tax law places an annual limitation on the amount of NOLs that may be used. As of the filig date of this report, we have not completed our Section 382 analysis in connection with the merger.

If we were to have taxable income in excess of the 382 Limitation following a Section 382 “ownership change,” we would not be able to offset tax on the excess income with the NOLs. Although any loss carryforwards not used as a result of any Section 382 Limitation would remain available to offset income in future years (again, subject to the Section 382 Limitation) until the NOLs expire, the “ownership change” could significantly defer the utilization of the loss carryforwards, accelerate payment of federal income tax and may cause some of the NOLs to expire unused.

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CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS [Abstract]
Revenues	$ 5,065,096	$ 7,070,540
Operating expenses
Lease operating expense	4,913,313	4,560,201
Depreciation, depletion, and amortization	910,837	1,121,018
Accretion	1,043,928	1,056,508
Consulting fees - related party	6,754	196,384
Acquisition-related costs - related party	0	34,834,752
General and administrative expense	4,585,450	4,198,747
Total operating expenses	11,460,282	45,967,610
Loss from operations	(6,395,186)	(38,897,070)
Consulting and other income (expense)	23,134	1,145,997
Interest expense, net	(132,955)	(149,131)
Loss on sale of available for sale securities	0	(517,920)
Impairment of available for sale securities	0	(275,327)
Gain on derivative warrant liability	0	1,056,224
Loss on disposal of assets	(23,990)	(14,054)
Foreign currency transaction gain (loss)	(21,253)	(5,884)
Net loss before income taxes	(6,550,250)	(37,657,165)
Income tax provision	(4,599)	122,949
Net loss	(6,554,849)	(37,534,216)
Less: Net loss attributable to noncontrolling interests	(5,527)	(8,483)
Net loss attributable to Hydrocarb Corporation	(6,549,322)	(37,525,733)
Dividend on preferred stock	(34,254)	(69,920)
Deemed dividend on preferred stock	(150,548)	0
Accretion dividend - Beneficial Cash Feature on preferred stock	(949,808)	0
Net loss attributable to Hydrocarb Energy Corp after dividends	$ (7,683,932)	$ (37,595,653)
Basic and diluted loss per common share: (in dollars per share)	$ (0.51)	$ (8.66)
Weighted average shares outstanding (basic and diluted) (in shares)	15,150,782	4,342,864

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Impairment

12 Months Ended

Jul. 31, 2014

Impairment [Abstract]

Impairment

Note 6 - Impairment

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 July 31, 2014 and July 31, 2013, 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.

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Oil and Gas Properties

12 Months Ended

Jul. 31, 2014

Oil and Gas Properties [Abstract]

Oil and Gas Properties

Note 5 – Oil and Gas Properties

Oil and natural gas properties consisted of the following:

For the year ended July 31,	2014			2013
Evaluated Properties
Costs subject to depletion	$	19,153,125		$	19,857,842
Accumulated impairment		(373,335	)		(373,335	)
Accumulated depletion		(3,491,420	)		(2,617,478	)
Total evaluated properties		15,288,370			16,867,029
Unevaluated properties		2,119,769			1,124,805
Net oil and gas properties	$	17,408,139		$	17,991,834

Evaluated properties

Additions to evaluated oil and gas properties during the year ended July 31, 2014 and 2013 consisted mainly of exploration costs, geological and geophysical costs of $34,029 and $157,818, respectively.

Effective September 1, 2013, we conveyed our interest in the Dix, Melody, Curlee, Palacios and Illinois properties to Carter E&P, LLC in conjunction with our termination of Steven Carter as Vice President of Operations for $0 cash proceeds and the assumption of the abandonment liabilities of $4,381. In accordance with full cost rules, we recognized no gain or loss on the sale.

Effective March 25, 2014, we conveyed our interest in the Barge Canal Welder properties to Winright Oil Company, LLC.  We received net proceeds of $625,000 for this conveyance.  In accordance with full cost rules, we recognized no gain or loss on the sale.

Unevaluated Properties

Namibia, Africa

In September 2012, we acquired a 39% (43.33% cost responsibility) working interest in a concession in Namibia, Africa.  In September 2012, we acquired a 39% (43.33% cost responsibility) working interest in a concession in Namibia, Africa. With our acquisition of HCN in December 2013, we acquired an additional 51% (56.67% cost responsibility) and we now own 90% (100% cost responsibility) of this concession, as described above in Note 2 –Acquisitions.  This property is a 5.3 million-acre concession in northern Namibia in Africa.

For the year ended July 31, 2014 we have incurred total costs of $1,406,114, including NEI’s cost basis incurred upon acquisition of the property, which was $562,048.  For the year ended July 31, 2013 we incurred total costs of $713,655, including NEI’s cost basis incurred upon acquisition of the property, which was $562,048. 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 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.

As of July 31, 2014, approximately $2.1 million has been expended towards the initial exploration period.  As of July 31, 2013, approximately $900,000 has been expended towards the initial exploration period.

Additions to unevaluated properties for the year ended July 31, 2014 consisted primarily of:

(1) Approximately $800,000 of exploration costs associated with the acquisition of aerial gravity and magnetic data over the Namibia concession, and

(2) Approximately $129,000 of leasehold costs, specifically payment of the annual concession fee to the Government of Namibia.

Offshore property

Our subsidiary, GBE, has interests in multiple leases with the State of Texas General Land Office in Galveston Bay. Through GBE, our primary operations are offshore in Galveston Bay. Significant changes to our offshore assets in Galveston Bay during the year ended July 31, 2014 include:

● Cost for a recompletion of Fisher Reef 2-3A#1;

● Cost for plugging/abandonment of two onshore wells;

● Costs for workover of Point Barrow salt water disposal well #1;

● Infrastructure enhancements; and

● Increase in asset retirement obligations primarily due to changes in timing and in estimated costs for the gathering systems located in Galveston Bay.

Sales of properties

In September 2012, we sold our 6.25% overriding royalty interests in properties located in Franklin and Richard parishes in Louisiana, the “Holt” and “Strahan” properties, to the operator of the properties and released the operator from any further liability from the note receivable in exchange for $50,000 cash.  We allocated the cash proceeds between an outstanding, and fully reserved, note receivable we held on the property and the overriding royalty interests based on the relative fair value of the balance on the note and the projected present value of the income streams from the royalty interests.  The portion attributable to the overriding royalty interest, $32,146, was treated as a reduction of capitalized costs in accordance with rules governing full cost companies.

In December 2012, we sold our 3% working interest in the producing Janssen lease located in Karnes County, Texas. We received $2,500 as cash proceeds in conjunction with the sale. The buyer assumed the asset retirement obligation for the well, which was $438. In accordance with full cost rules, we recognized no gain or loss on the sale.

Effective September 1, 2013, we conveyed our full interest in the Illinois, Palacios, Curlee, Dix, and Melody properties to Carter E&P in conjunction with our termination of Steven Carter as Vice President of Operations for $0 cash proceeds and the assumption of the abandonment liabilities.

Effective March 25, 2014, we conveyed our interest in the Barge Canal Welder properties to Winright Oil Company, LLC.  We received net proceeds of $625,000 for this conveyance.  In accordance with full cost rules, we recognized no gain or loss on the sale.

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Description of Business and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Jul. 31, 2014

Description of Business and Summary of Significant Accounting Policies [Abstract]

Description of business and basis of presentation

Description of business and basis of presentation

We are a natural resource exploration and production company engaged in the exploration, acquisition, development, and production of oil and gas properties in the United States and onshore in Namibia, Africa.  We were incorporated under the laws of the State of Nevada on April 12, 2005 under the name “Carlin Gold Corporation”. On July 19, 2005, we changed our name to “Nevada Gold Corp.” On October 18, 2005, we changed our name to “Gulf States Energy, Inc.” and increased our authorized capital from 100,000,000 shares of common stock to 500,000,000 shares of common stock, par value $0.001 per share. On September 5, 2006, we changed our name to “Strategic American Oil Corporation”.  On April 4, 2012 we completed a one new share for twenty-five old share (1:25) reverse stock split and as a result our authorized capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock.  Also, effective April 4, 2012, we changed our name to “Duma Energy Corp.”  Effective May 16, 2012, we increased our authorized capital from 20,000,000 shares to 500,000,000 shares of common stock.  Effective November 29, 2013, the Company increased the number of its authorized shares of common stock from 500,000,000 to 1,000,000,000 shares of common stock.    Effective February 18, 2014, we changed our name from Duma Energy Corp. to Hydrocarb Energy Corp.  Effective May 8, 2014, we effected a 1:3 reverse split of our authorized common stock and a corresponding 1:3 reverse split of our outstanding common stock.  All share and per share amounts for all periods in this report have been retroactively restated to reflect the reverse split. Our capitalization at July 31, 2014 was 333,333,334 authorized common shares with a par value of $0.001 per share.  Our common stock is quoted under the symbol “HECC” on the OTCBB.

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.

We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas limited liability company, (iii) SPE Navigation I, LLC, a Nevada limited liability company, (iv) Namibia Exploration, Inc., a Nevada corporation, (v) Hydrocarb Corporation, a Nevada corporation, (vi) Hydrocarb Texas Corporation, a Texas corporation, and (vii) Hydrocarb Namibia Energy (Pty) Limited, a company chartered in the Republic of Namibia.  In addition, we own 95% of the issued and outstanding share capital of Otaiba Hydrocarb LLC, a UAE limited liability corporation.

As of July 31, 2014, we maintain developed and undeveloped acreage offshore in Texas.  As of July 31, 2014, we were producing oil and gas from our working interest in four offshore fields in Galveston Bay, Texas.  During September 2012, we acquired, through the acquisition of Namibia Exploration Inc., a 39% non-operated working interest in a concession located onshore in Namibia, Africa.  During December 2013, with our acquisition of Hydrocarb Corporation, we acquired 51% working interest in this onshore Namibia, Africa concession and now own 90% working interest (100% cost responsibility) in the Namibia, Africa concession.

Reclassifications

Reclassifications

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

Principles of consolidation

Principles of consolidation

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 accompanying consolidated financial statements include the accounts of Hydrocarb Energy Corp., our wholly owned subsidiaries Penasco Petroleum Corporation (“Penasco”), SPE Navigation I, LLC (“SPE”), Galveston Bay Energy, LLC (“GBE”), Namibia Exploration, Inc. (“NEI”), Hydrocarb Corporation (“HCN”), Hydrocarb Texas Corporation, and Hydrocarb Namibia Energy (Pty) Limited.  In addition, these financials include our 95% ownership interest in Otaiba Hydrocarb LLC.  All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of estimates

Use of estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

Significant areas requiring management’s estimates and assumptions include the determination of the fair value of transactions involving stock-based compensation and financial instruments, estimates of the costs and timing of asset retirement obligations, and oil and natural gas proved reserve quantities.  Oil and natural gas proved reserve quantities form the basis for the calculation of amortization of oil and natural gas properties and for asset impairment tests. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories.

Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.

Cash and cash equivalents

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.

Receivables and allowance for doubtful accounts

Receivables and allowance for doubtful accounts

Oil and gas revenues receivable are recorded at the invoiced amount and do not bear any interest. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Management has determined that a reserve for uncollectible amounts was not required in the periods presented.

Accounts receivable – related party includes the oil and gas revenue receivable from our Barge Canal properties, which, up until September 1, 2013, were operated by a company owned by one of our former officers who was also a director, and joint interest billings receivable from two working interest partners who are related to our former Chief Financial Officer, the former Chief Executive Officer and the current Chief Executive Officer. This balance also includes an oil and gas receivable from Lifestream, LLC, a company owned by the brother of our current CEO.

Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate.

We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.  As of July 31, 2014 and 2013, we have reserved $70,742 and $58,585, respectively, for potentially uncollectable other receivables.

Available for sale securities

Available for sale securities

We invest in marketable equity securities which are classified as available for sale. The first in first out method is used to determine the cost basis of our equity securities sold. Available-for-sale securities are marked to market based on the fair values of the securities determined in accordance with ASC Section 820 (Fair Value Measurement), with the unrealized gains and losses, net of tax, reported as a component of accumulated other comprehensive income (loss).

Other current assets

Other current assets

Other current assets consist primarily of prepaid insurance, prepaid interest expense, prepayments made towards properties not operated by us, and accrued interest on our deposits.

Concentrations

Concentrations

Our operations are concentrated in Texas and the majority of our operations are conducted offshore in Galveston Bay.  We operate in the oil and gas exploration and production industry. If the oil and natural gas exploration and production industry as a whole were adversely affected, for example by weather, supply shortages, or other factors, we would also experience adverse effects. Because our properties are offshore, we are also vulnerable to adverse weather.

For the year ended July 31, 2014, 83% of our revenue was attributable to one purchaser.  At July 31, 2014, this same purchaser accounted for 88% of our accounts receivable. For the year ended July 31, 2013, 85% of our revenue was attributable to one purchaser.  At July 31, 2013, this same purchaser accounted for 76% of our accounts receivable.

We place cash with high quality financial institutions and at times may exceed the federally insured limits. We have not experienced a loss in such accounts nor do we expect any related losses in the near term.

Oil and natural gas properties

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.

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 unit 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.

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.

Impairment

Impairment

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 proved 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.  During the years ended July 31, 2014 and July 31, 2013, the ceiling exceeded the net book value of the property and it was not necessary to record an impairment charge.

Asset retirement obligation

Asset retirement obligation

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 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 update our assessment accordingly. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gathering systems as these obligations are incurred.

Restricted cash

Restricted cash

Restricted cash consists of certificates of deposit that have been posted as collateral for letters of credit supporting bonds guaranteeing remediation of our oil and gas properties in Texas and escrow funds deposited directly with regulatory authorities. As of July 31, 2014 and 2013, restricted cash totaled $6,877,944 and $6,920,739, respectively.

Other assets

Other assets

Other assets at July 31, 2014 and 2013 consisted primarily of prepaid land use fees, which are payments that cover multiple years (typically ten years) rental for easements and surface leases.  These are paid as they come due on an ongoing basis and amortized over the rental period.  In addition, other assets also include a domain name for $30,267, which is an intangible asset with an indefinite life due to the fact that it is renewable annually for nominal cost.  We evaluate intangible assets with an indefinite life for possible impairment at least annually by comparing the fair value of the asset with its carrying value.

Property and equipment, other than oil and gas

Property and equipment, other than oil and gas

Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally three to five years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. We perform ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.

Impairment of long-lived assets

Impairment of long-lived assets

We periodically review our long-lived assets, other than oil and gas property, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. We recognize an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value. We recorded no impairment on our non-oil and gas long-lived assets during the years ended July 31, 2014 and 2013, respectively.

Advances

Advances

Advances consist of prepayments received from working interest partners pertaining to their share of the costs of drilling oil and gas wells.  Partners are billed in advance for the estimated cost to drill a well and as the work proceeds, the prepayment is applied against their share of the actual drilling cost.  As of July 31, 2014 and 2013, advances totaled $195,904 and $180,804, respectively.

Revenue recognition

Revenue recognition

We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. Actual sales of gas are based on sales, net of the associated volume charges for processing fees and for costs associated with delivery, transportation, marketing, and royalties in accordance with industry standards. Operating costs and taxes are recognized in the same period in which revenue is earned.  Severance and ad valorem taxes are reflected as a component of lease operating expense.

Income taxes

Income taxes

We account for income taxes using the asset and liability method. Under this method, deferred income tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Fair value

Fair value

Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.

Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.

The three-level hierarchy is as follows:

● Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.

● Level 2 inputs consist of quoted prices for similar instruments.

● Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  We have determined that certain warrants outstanding during the period covered by these financial statements qualify as derivative financial instruments under the provisions of FASB ASC Topic No. 815-40, “Derivatives and Hedging – Contracts in an Entity’s Own Stock.” (See Note 8 – Fair Value).

The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain on derivative warrant liability.”

Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.

We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2014 or July 31, 2013. The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable – related party, accounts payable and accrued expenses, and notes payable approximate their fair market value based on the short-term maturity of these instruments.

Stock-based compensation

Stock-based compensation

ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.

We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.”  ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete.  Generally, our awards do not entail performance commitments.  When an award vests over time such that performance occurs over multiple reporting periods, 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 vesting date, which is presumed to be the date performance is complete.

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.

Stock Split

Stock Split

On May 8, 2014, we affected a 1-for-3 reverse stock split.  All share and per share amounts 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 or the effective date of the registration statement, whichever is later.

Earnings per share

Earnings per share

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share includes the dilutive effects of common stock equivalents on an “as if converted” basis. For the years ended July 31, 2014 and 2013, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.

Contingencies

Contingencies

Legal

We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.  See Note 13 - Commitments and Contingencies for more information on legal proceedings.

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.

Accumulated Other Comprehensive Income (Loss), net of tax

Accumulated Other Comprehensive Income (Loss), net of tax

We follow the provisions of ASC 220, "Comprehensive Income", which establishes standards for reporting comprehensive income. In addition to net loss, comprehensive loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company.

Recent accounting pronouncements

Recent accounting pronouncements

In March 2013, the FASB amended ACS 830, Foreign Currency Matters, to clarify the appropriate accounting when a parent ceases to have a controlling interest in a subsidiary or group of assets that is a business within a foreign entity. This clarification provides that the cumulative translation adjustment should only be released into net income if the loss of controlling interest represents complete or substantially complete liquidation of the foreign entity in which the subsidiary or asset group had resided. This amendment is effective for us starting with our first quarter of fiscal year 2015 and adoption would impact our consolidated financial condition and results of operations if we dispose of a foreign entity.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (“ASU No. 2014-09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance when it becomes effective. This new standard is effective for us starting with our first quarter of fiscal year 2018.  Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

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.

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Commitments and Contingencies

12 Months Ended

Jul. 31, 2014

Commitments and Contingencies [Abstract]

Commitments and Contingencies

Note 13 – Commitments and Contingencies

Contingencies

Legal

We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.

As of July 31, 2014, we were party to the following legal proceedings:

Cause No. 2011-37552; Strategic American Oil Corporation v. ERG Resources, LLC, et al.; In the 55th District Court, Harris County, Texas. The Company is a plaintiff in this suit. In this case, Company brought claims for injunctive relief, breach of contract and fraudulent inducement against the defendant regarding the purchase of Galveston Bay Energy, LLC from ERG. The Company intends to prosecute its claims and defenses vigorously. As of the date of filing of this report, the Company is no longer seeking injunctive relief. Additionally, the below listed case has been consolidated into this case since the subject matter of the below case is subsumed within the subject matter of this case. From this point forward, there will be only this one piece of litigation. The trial was held in October 2013. The judge ruled in favor of ERG and that Hydrocarb is liable to pay the charges in the below-mentioned case and a portion of ERG’s attorney fees. The Company is in the process of post-trial motions and no judgment has been entered as of this date.  As of July 31, 2013, the Company had accrued $232,974 for this cause.

Cause No. 2011-54428; ERG Resources, LLC v. Galveston Bay Energy, LLC, in the 125th Judicial District Court, Harris County, Texas. This case deals with the operating agreements for the processing of product by the entities owned by ERG. It is an action seeking payments of charges and expenses by ERG that are refuted by GBE. The Company intends to prosecute its claims and defenses vigorously. As indicated above, this case has been consolidated into the case listed above. As such, the claims in this case will be decided in cause No. 2011-37552, which was tried in October 2013.

Settlement negotiations on both these matters have been concluded.  Galveston Bay has paid $35,000 in cash and Hydrocarb Energy will issue $65,000 in common stock to settle.  More than this amount has been accrued previously and no further adjustments will be made to our financial statements.

A state regulator has requested that we renew certain pipeline easements located in Galveston Bay. The easements in question were originally obtained by another company whose successor filed for bankruptcy protection.  Our subsidiary, Galveston Bay Energy, LLC purchased certain assets from the bankruptcy estate; however, based on the bankruptcy court’s order and the purchase and sale agreement, we believe the pipelines and easements in question were not included in assets purchased. The easements in question were scheduled to renew at various dates between 2012 and 2021.  Based on current posted rates, the cost of renewal of all of the easements would be approximately $400,000.  We have engaged legal counsel to dispute the regulator’s claim.  If we are obligated to renew these easements, they would be part of the asset retirement obligation that was acquired with our subsidiary, Galveston Bay Energy, LLC. As such, the potential liability for these easements is factored into the computation of the asset retirement obligation (See Note 7 – Asset Retirement Obligation) that is estimated using the guidance in ASC 410-20, Asset Retirement and Environmental Obligations.  On August 29, 2014, we filed a lawsuit in the state district court in Chambers County, Texas asking the Court to reform an assignment and assumption agreement in the property records of Chambers County.  The General Land Office has asserted claims against us under various miscellaneous easements, claiming we are obligated to either renew the easement or remove any pipeline laid in the easement.  We have disclaimed any obligations under these easements.

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.

There is soil contamination at a tank facility owned by GBE. Depending on the technique used to perform the remediation, we estimate the cost range to be between $150,000 and $900,000. We cannot determine a most likely scenario, thus we have recognized the lower end of the range. We have submitted a remediation plan to the appropriate authorities and have not yet received a response. For the year ended July 31, 2014 and July 31, 2013, $150,000 has been recognized and is included in the balance sheet caption “Accounts payable and accrued expenses.”

Commitments

In March 2011, we executed a lease for office space in Houston, Texas.  The lease term was three years and we had an option to extend the lease for an additional three years.  Our scheduled rent was $6,406 per month plus common area maintenance cost for the first year, $6,673 plus common area maintenance cost for the second year, and $6,940 per month plus common area maintenance cost for the third year.  We did not extend this lease, but entered into a sublease arrangement with Greenshale LLC for office space in the same building.  During September 2013, we terminated our lease for office space in Corpus Christi, Texas.

In April 2012, we executed a Compression and Handling Agreement (the “PHA”) with another operator. Under the terms of the PHA, oil, natural gas, and salt water from one of our fields would be disposed of through the operator’s facility. Under the agreement, we are responsible for approximately a flat fee of $1,000 per month as a gauging fee, our pro-rata share of repairs at the facility, and compression, salt water disposal, and other charges based on the volumes disposed of through the facility.

Rent expense during the years ended July 31, 2014 and 2013 was $186,463 and $211,346, respectively. See Note 8 – Notes Payable for details regarding our commitments related to our future obligations.

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.

During the year ended July 31, 2014 and 2013 we prepaid the fees associated with the Greenbank letters of credit for the respective year interest upfront and amortized these fees on a straight-line basis over their respective annual periods. The following table reflects the prepaid balances as follows:

July 31,	2014			2013
Prepaid letter of credit feees	$	101,251		$	101,850
Amortization		(8,488	)		(8,488	)
Net prepaid letter of credit fees	$	92,763		$	93,362

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Fair Value

12 Months Ended

Jul. 31, 2014

Fair Value [Abstract]

Fair Value

Note 9 – Fair Value

Fair value is defined as the amount that would be received for selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company categorizes financial assets and liabilities into the three levels of the fair value hierarchy. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value and bases categorization within the hierarchy on the lowest level of input that is available and significant to the fair value measurement.

● Level 1 — Quoted prices in active markets for identical assets or liabilities;

● Level 2 — Observable inputs other than Level 1, such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; and

● Level 3 — Significant unobservable inputs that are supported by little or no market activity or that are based on the reporting entity’s assumptions about the inputs.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

At July 31, 2014 and 2013 we had no financial assets and liabilities requiring measurement at fair value on a recurring basis.  We had no transfers in or out of either Level 1 or Level 2 fair value measurements during the years ended July 31, 2014 and 2013. During the annual 2013 period, we did recognize changes in the fair value measurement of our Level 3 derivative warrant liability during the years ended July 31, 2013.  No fair value measurement Level 3 derivative warrant liabilities existed during the year ended July 31, 2014.

Derivative Warrant Liabilities

Warrants – Third Party

During the year ended July 31, 2010 we issued certain warrants which contained a down-ratchet provision on the exercise price of the warrants.  In accordance with accounting guidance we utilize FASB ASC Topic No. 815-40 to determine whether an instrument (or embedded feature) is indexed to an entity’s own stock. This literature specifies when a contract would otherwise meet the definition of a derivative but that both (a) indexed to our stock and (b) classified in stockholders’ equity in our statement of financial position, would not be considered a derivative financial instrument.  The guidance provides a two-step model to be applied in determining whether a financial instrument or embedded feature is indexed to an issuer’s own stock and thus able to qualify for the scope exception.

Based upon this guidance the warrants issued during the year ended July 31, 2010 were not afforded equity treatment due to the down-ratchet provision on the exercise price.  As a result, the warrants were not considered indexed to our own stock, and as such, the fair value of the embedded derivative liability was reflected on the balance sheet and all future changes in the fair value of these warrants were recognized currently in earnings in our consolidated statement of operations under the caption “Gain (loss) on warrant derivative liability” until such time as the warrants are exercised or the down-ratchet provision expires.

The warrants were fair valued using a multi-nominal lattice model with the following assumptions:

● The stock price on the valuation date would fluctuate with our projected volatility;

● Warrant holders would exercise at target price multiples of the market price trigger prices.  The target price multiple reduces as the warrants approach maturity;

● Warrant holders would exercise the warrant at maturity if the stock price was above two times the reset exercise price;

● An annual reset event would occur at 65% discount to market price; and

● The projected volatility was based on historical volatility.  Because we did not have sufficient trading history to determine our own historical volatility, we used the volatility of a group of comparable companies combined with our own historical volatility from May 2009, when we began trading.

The unrealized gain on changes in fair value was recorded as a reduction of the derivative liability and as an unrealized gain on the change in fair value of the liability in our statement of operations.  The warrant agreement provides that the antidilution provisions expire three years after the grant of the warrants.  Accordingly, the provision for warrants to purchase 206,400 shares of commons stock expired on November 13, 2012 and the warrants were determined to no longer be derivatives.  The outstanding warrant liability, as a result, was reclassified to additional-paid-in-capital and the fair value was determined for a final mark-to-market adjustment.

The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability as follows:

As of July 31,	2014		2013
Beginning of period	$	-	$	1,325,388
Expiration of derivative warrant feature		-		(269,164	)
Unrealized gain on changes in fair value of derivative liability		-		(1,056,224	)
End of period	$	-	$	-

Warrants – 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 as described in Note 11 – Related Party Transactions. 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, warrants to purchase 200,000 shares with an exercise price of $7.50 per share 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, warrants to purchase 200,000 shares 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.  As of July 31, 2014, the expense for the warrants was fully amortized.

In accordance with accounting guidance, the fair value of the warrants that vest upon the attainment of a market condition is expensed and amortized over the lower of the implicit or derived service period of the warrants.  Any previously recognized expense is not reversed in the event of a subsequent decline in the fair value of market condition equity based compensation. During the year ended July 31, 2013, $1,056,224 of unrealized non-cash gains were recognized as fair value adjustments within Level 3 of the fair value measurement hierarchy and were recorded as a reduction of the derivative warrant liability and an unrealized gain on the change in fair value of the liability in our statement of operations. (See Note 10 – Capital Stock, for further details surrounding our warrant liability.

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Additional Financial Statement Information (Schedule of Property and Equipment) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Property, Plant and Equipment [Line Items]
Total property and equipment	$ 302,553	$ 174,998
Less accumulated depreciation	(135,590)	(116,945)
Net book value	166,963	58,053
Depreciation expense	36,894	61,215
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	5 years
Total property and equipment	24,085	8,814
Marine vessels [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	5 years
Total property and equipment	109,742	17,614
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	5 years
Total property and equipment	40,496	65,807
Computer equipment and software [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	2 years
Total property and equipment	126,143	82,466
Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	2 years
Total property and equipment	2,087	0
Other Depreciable Property [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	2 years
Total property and equipment	$ 0	$ 297

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Asset Retirement Obligation

12 Months Ended

Jul. 31, 2014

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

Note 7 – Asset Retirement Obligation

The following is a reconciliation of our asset retirement obligation liability as of July 31, 2014 and 2013, respectively.

	2014			2013
czReconciliation of asset retirement obligation balance
Liability for asset retirement obligation, beginning of period	$	10,933,398		$	9,382,933
Asset retirement obligations sold		(33,195	)		(438	)
Asset retirement obligations incurred on properties drilled		-			26,500
Accretion		1,043,928			1,056,508
Revisions in estimated cash flows		(104,237	)		786,120
Costs incurred		(123,664	)		(318,225	)
Liability for asset retirement obligation, end of period	$	11,716,230		$	10,933,398
Current portion of asset retirement obligation	$	1,133,690		$	724,374
Noncurrent portion of asset retirement obligation		10,582,540			10,209,024
Total liability for asset retirement obligation	$	11,716,230		$	10,933,398

Estimated Timing of asset retirement obligation payments:

Fiscal Year	Pipelines		Easements		Wellbores		Facilities		Total
2015	$	126,290	$	-	$	997,400	$	10,000	$	1,133,690
2016	$	60,000	$	27,516	$	639,725	$	-	$	727,241
2017	$	99,938	$	66,006	$	191,476	$	837,436	$	1,194,856
2018	$	55,040	$	14,475	$	548,700	$	-	$	618,215
2019	$	52,621	$	10,429	$	572,337	$	221,757	$	857,144
2020 to 2024	$	980,713	$	193,283	$	2,269,781	$	848,211	$	4,291,988
2025 to 2029	$	236,898	$	67,089	$	1,356,391	$		$	1,660,378
2030 to 2034	$	44,439	$	145,197	$	143,578	$	899,504	$	1,232,718
Thereafter	$	-	$	-	$	-	$	-	$	-
Total	$	1,655,939	$	523,995.06	$	6,719,388	$	2,816,908	$	11,716,230

The above dismantlement, restoration or abandonment obligations relate to the Company's following properties: (1) a combined total of 45 pipelines located in Chambers County, Texas and Galveston County, Texas (2) a combined total of 135 surface or right of way easements located in Chambers County. Texas and Galveston County, Texas (3) a combined total of 143 wellbores located in Chambers County, Texas and Galveston County, Texas and (4) a combined total of 8 facilities located in Chambers County, Texas and Galveston County, Texas.

The Company's ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company's oil and gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

As of July 31, 2014, the Company does not have any active dismantlement, restoration or abandonment activities in progress or underway. During the year ended July 31, 2014, the Company plugged 3 wells reducing its wellbore retirement obligations from those previously reported for the year ended July 31, 2013. The Company historically conducts all such remediation activities during the winter or spring periods, which have yet to be determined as of the date of this filing. "

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Notes Payable

12 Months Ended

Jul. 31, 2014

Notes Payable [Abstract]

Notes Payable

Note 8 – Notes Payable

Line of Credit

On March 17, 2011, GBE secured a one year revolving line of credit of up to $5 million with a commercial bank. The note specified interest at a rate of prime + 1% with a minimum interest rate of 5% per annum. The initial interest rate was 6%, and interest is payable monthly. Proceeds from the line of credit were used solely to enhance our Galveston Bay properties.  The note was collateralized by our Galveston Bay properties and substantially all of GBE’s assets. HEC also executed a parental guarantee of payment. The note was extended several times during fiscal 2013 and finally replaced by a term loan note in June 2013.  We held no balance outstanding on our line of credit for the years ended July 31, 2014 and July 31, 2013, respectively.  During the year ended July 31, 2014, we closed our LOC with the commercial bank and replaced it with an installment note payable.  See below for further details.

HCN Note Payable

During September 2012, in conjunction with the acquisition of NEI, HEC entered into a Consulting Services Agreement with HCN (the "Consulting Agreement”) which obligated HEC to pay a consulting fee (the "Fee") to HCN of $2,400,000 as follows:

(a) $800,000 on September 6, 2012, which was 15 days from the date that the Minister of Mines and Energy consented to the assignment of a 39% working interest in the Namibian concession to HEC, and

(b) $1,600,000 note payable, with principal payments of $800,000 each due on August 7, 2013 and August 7, 2014.

Interest accrued on the principal amount at the rate of 5% per annum, calculated semi-annually and payable in arrears. At HEC’s sole discretion, it could pay the first tranche of the Fee and principal associated with the note payable using HEC common stock. HEC was required to pay a late fee of 10% per quarter for any outstanding balance of the Fee under the Consulting Agreement which  commenced 30 calendar days from the date that the Fee or portion of the Fee is due, which by the terms of the Consulting Agreement may only be paid in cash.  The Consulting Agreement is more fully described in our audited financial statements for the year ended July 31, 2013, contained in our Annual Report filed with the SEC on Form 10-K.

In October 2013, prior to our acquisition of HCN, HEC settled the then-outstanding $2,400,000 Fee and $553,630 of interest and late fees associated with the Fee by issuance of HEC common stock (See Note 7 - Capital Stock). Further, $25,000 of the related interest and fees was settled in cash.  As the acquisition of HCN is accounted for as an acquisition of an entity under common control and prior reporting periods in these financial statements have been appropriately adjusted as if the acquisition had occurred at the beginning of the comparative periods, this note and related amounts have been removed from these financial statements.

Installment Notes Payable

In May 2012, we entered into a note payable of $18,375 to purchase a 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 $5,530 and $11,678 as of July 31, 2014 and July 31, 2013, respectively.

In March 2013, we financed our commercial insurance program using a note payable for $260,905. Under the note, we were obligated to make nine payments of $29,591 per month, which include principal and interest, beginning in March 2013. The principal balance owed on the note payable as of July 31, 2013, was $115,958.  No amounts were owed on the note payable as of July 31, 2014.

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 July 31, 2014, the note payable balance was $179,158.

As noted above, in June 2013, the outstanding balance on our line of credit of $300,000 was replaced by a term loan that matures on June 22, 2015. Under the term loan, we are obligated to make twenty four monthly payments of $12,500 representing principal reduction plus interest per month. The note accrues annual interest at prime + 1%, currently totaling 6%.  As of July 31, 2014 and July 31, 2013, the balance outstanding related to this note was $150,000 and $275,000, respectively.  The July 2014 payment of $12,500 was not made and as a result, the Company incurred $663 in late fees and interest.  In August 2014, the Company paid off the outstanding balance of $150,000 plus accrued interest and fees, in connection with entering into the Credit Agreement with Shadow Tree Capital Management (see Note 15 - Subsequent Events, below).

Maturities of our long term debt obligation at July 31, 2014 are as follows:

Year ending July 31,	2015		Thereafter		Total
Operating and capital leases	$	-	$	-	$	-
Notes payable		334,688		-		334,688
Total	$	334,688	$	-	$	334,688

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Capital Stock

12 Months Ended

Jul. 31, 2014

Capital Stock [Abstract]

Capital Stock

Note 10 – Capital Stock

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

	Warrant B		Warrant C
Fair Value	$	266,017	$	206,245

The following table reflects information regarding Warrant B and Warrant C during the year ended July 31, 2014 and 2013.

	July 31, 2014		July 31, 2013
	Warrant B		Warrant C
Compensation Expense recognized	$	6,754	$	196,384

Stock Split

Effective on May 8, 2014, we affected a 1:3 reverse split of our authorized common stock and a corresponding 1:3 reverse split of our outstanding common stock.  All share and per share amounts for all periods in this report have been retroactively restated to reflect the reverse split.

Effective November 29, 2013, the Company increased the number of its authorized shares of common stock from 166,666,667 shares, par value $0.001 per share to 333,333,334 authorized common shares with a par value of $0.001 per share.

Our capitalization at July 31, 2014 was 333,333,334 authorized common shares with a par value of $0.001 per share.

Series A Preferred Stock

On December 2, 2013, we filed a Certificate of Designation that created a new class of stock: Series A 7% Convertible Voting Preferred Stock (“Series A Preferred”).  Up to 10,000 shares of Series A Preferred are authorized. The stock has a stated value of $400 per share, pays annual dividends at 7%, and is convertible into HEC common stock, at the holder’s option, at a conversion rate of $6.00 per share. The Series A Preferred is neither redeemable nor is it callable. Series A Preferred shareholders may vote their common stock equivalent voting power. We analyzed the Series A Preferred using the guidance contained in ASC 815-40, Derivatives and Hedging, and concluded that the instrument was indexed to our own stock and qualified to be included in stockholders’ equity.

In connection with the acquisition of HCN on December 9, 2013, HEC issued 8,188 shares of our Series A Preferred Stock to a former Preferred Stock shareholder of HCN, as described in Note 2 – Acquisitions, above.  The value of the preferred stock at issuance was $3,275,200 (8,188 shares at par value of $400).  These shares were recorded in equity at par of $3,275,200.  Because the Series A preferred stock is immediately convertible, the value of a beneficial conversion feature of $949,808 was immediately recognized as a dividend.  During the year ended July 31, 2014, the holder of the Series A Preferred Stock received dividends of $34,254.  As of July 31, 2014, additional dividends have not been accrued as liabilities since they were not declared by the Company.

Common Stock Issuances

During September 2012, we issued 2,830,000 shares of common stock to the owners of Namibia Exploration, Inc. (“NEI”) for the acquisition of NEI.  The shares were valued at $3,784,800, based on the quoted market price of our stock on the date of the acquisition. Additionally, $31,612,000 was recognized in conjunction with our commitment to issue additional stock if certain market conditions are achieved. (See Note 2 – Acquisitions – Namibia Exploration, Inc.)

On October 31, 2013, we issued 619,960 shares of common stock to HCN to settle the $2,400,000 Fee as described in Note 8 – Notes Payable, $553,630 of interest and late fees associated with the Fee, and $635,937 of joint interest billings payable to HCN for its work on the Namibian concession.  The shares were valued and recorded at $3,589,567, based on the value of the obligations settled.

In connection with the acquisition of HCN on December 9, 2013, we issued 8,396,667 shares of our common stock, as described in Note 2 – Acquisitions, above.  These common stock shares were recorded in equity at par of $8,397 partially offset by additional paid-in capital of $1,837, as described above in Note 2 – Acquisitions.

In conjunction with the HCN acquisition, we issued 7,470,000 shares of our common stock to the former owners of NEI.  These shares were contingently-issuable consideration for the acquisition of NEI and we valued them at $31,612,000 and recorded it as Acquisition-related costs - related party expense in September 2012.

During the year ended July 31, 2014, we issued 167,904 shares of common stock, to employees and directors for services performed.  In conjunction with the issuance of these shares we recognized $813,827 in compensation expense.

HCN Series A Preferred Stock

On December 3, 2013, before the HEC acquisition of HCN, HCN issued 3,963 shares of its Series A Preferred Stock to Kent Watts, HCN CEO, in order to cancel amounts owed to him for advances he made to the Company in the amount of $1,379,891 plus accrued interest and dividends owed to him of $205,309, totaling $1,585,200.  The HCN Series A Preferred Stock provided for cash dividends of 7% per year, payable in either cash or shares of stock, at the Company’s option.  During the year ended July 31, 2014, the HCN preferred stock accrued dividends of $39,230, which was satisfied through the issuance of the HCN preferred stock on December 3, 2013.  These 3,963 shares of preferred stock plus the previously outstanding 4,225 shares were exchanged for 8,188 shares HEC Series A Preferred Stock, as described above in the acquisition of HCN.

Receivables for Common Stock

On September 6, 2013, HCN sold 191,667 shares of HEC common stock to an employee of HCN in exchange for a note receivable in the amount of $1,000,000. This HCN employee is the nephew of our current CEO. 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 market or NYSE stock exchange. 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 market or stock exchange, we will receive up to $1,000,000, or the note can be paid earlier at the discretion of the other party. We collected $675,000 in cash on this note receivable through July 31, 2014.  At July 31, 2013, these shares were classified as treasury stock within equity at the cost HCN obtained them from outside entities for services performed following the consolidation of comparative periods for acquired entities under common control (See Note 2 –Acquisitions).  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 unrelated 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.

This note receivable was extended on August 4, 2014, for an extension fee of $50,000, payable in the future, with $750,000 due to be repaid by December 31, 2014, with the remaining balance to be repaid by March 31, 2015.  These repayment terms may be changed if the Company is successful in being up-listed to either the NYSE or NASDAQ.  If this occurs, the entire balance is due within 60 days after an up-listing occurs.

Stock Compensation Plans

As of July 31, 2014, HEC could grant up to 570,136 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.

A new 2013 Stock Incentive Plan (2013 Plan) was approved by the Board during February 2013. The 2013 Plan replaced our prior stock incentive plans. HEC may grant up to 883,333 shares of common stock under the 2013 Plan. The Plan is administered by the Board of Directors, which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.

The fair value of each option is estimated using the Black-Scholes valuation model. Expected volatility is based solely on historical volatility because we do not have traded options. Prior to May 2009, the volatility was determined by referring to the average historical volatility of a peer group of public companies because we did not have sufficient trading history to determine our own historical volatility.  Beginning with computations after May 2009, when there was an active trading market for our stock, we have included our own historical volatility in determining the volatility used.  As of October 2013, we determined that 4.5 years of trading history was sufficient to determine historical volatility; accordingly valuations from October 2013 onwards will be performed without using a peer group.

The expected term calculation for stock options is based on the simplified method as described in the Securities and Exchange Commission Staff Accounting Bulletin number 107. We use this method because we do not have sufficient historical information on exercise patterns to develop a model for expected term. The risk-free interest rate is based on the U. S. Treasury yield in effect at the time of grant for an instrument with a maturity that is commensurate with the expected term of the stock options. The dividend yield rate of zero is based on the fact that we have never paid cash dividends on our common stock and we do not intend to pay cash dividends on our common stock.

Options granted to non-employees

We account for options granted to non-employees under the provisions of ASC 505-50 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 vesting date, which is presumed to be the date the performance is complete.

In February 2013, options to purchase an aggregate of 200,000 shares of common stock with an exercise price of $6.60 per share and a term of ten years were granted to our three independent directors.  The options vest at the rate of 20% of such options each six months over the first 30 months following the grant date. The fair value of the total option award on the date of grant was $1,196,589. The fair market value of this award was estimated using the Black-Sholes option pricing model.

In August 2013, 13,333 of the 200,000 options granted to our independent directors became vested and the remainder of the previously unamortized fair value of these options, $16,184, was recognized on the vesting date. The fair value was estimated using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 2.01%, a dividend yield of 0%, and a volatility factor of 144.01%.

In October 2013, the board accelerated the vesting of the remaining 53,333 options so that they became fully and immediately vested.  The fair value of the options on the date of vesting of $810,738 was recognized immediately as an expense. The fair value was estimated using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 2.09%, a dividend yield of 0%, and a volatility factor of 117.31%.

In addition, during October 2013, the final tranche of certain options that had originally been granted to non-employees in April 2011 vested, for which we recognized $60,622 in expense.

The following table provides information about options granted to non-employees under our stock incentive plans during the years ended as follows:

As of July 31,	2014		2013
Number of options granted		-		200,000
Compensation expense recognized	$	887,544	$	679,174
Weighted average exercise price of options granted		N/A	$	6.60

The following table details the significant assumptions used to compute the fair market values of stock options granted or revalued during the years ended as follows:

As of July 31,		2014				2013
Risk-free interest rate	N/A		-	N/A	1.11%		-	2.00%
Dividend yield				0%				0%
Volatility factor	N/A		-	N/A	140.3%		-	144.0%
Expected life (in years)				N/A				6.5

Based on the fair value of the options as of July 31, 2014, there was no unrecognized compensation costs related to non-vested share based compensation arrangements granted to non-employees.

Options granted to employees

The following table provides information about options granted to employees under our stock incentive plans.

For the year end July 31,	2014		2013
Number of options granted		-		-
Compensation expense recognized	$	56,028	$	253,952
Weighted average exercise price of options granted		N/A		N/A

During the year ended July 31, 2011, options to purchase 86,667 shares of common stock with an exercise price of $7.50 per share and a term of ten years were granted to five employees.  The options vest at the rate of 20% of such option each six months over the first 30 months following the grant date. Because the grantees were employees, the awards are accounted for under the provisions of ASC 718.  Accordingly, they are measured at fair value on the date of grant and the expense associated with the grant will be amortized over the 30 month vesting period on a straight line basis.  As of July 31, 2014, we had no unamortized compensation expense associated with options granted to employees, as shares were either cancelled or accelerated as of July 31, 2014.

No options were granted to employees during the years ended July 31, 2014 or 2013.

Summary information regarding stock options issued and outstanding as follows:

	Options			Weighted average share price		Aggregate intrinsic value		Weighted average remaining contractual life (in years)
Outstanding at July 31, 2012	$	348,000		$	7.50		-		7.22
Granted		200,000			6.60
Exercised		-			-
Expired or forfeited		(36,000	)		7.50
Outstanding at July 31, 2013		512,000			6.81		-		7.98
Granted		-			-
Exercised		-			-
Expired or forfeited		(246,667	)		7.50
Outstanding at July 31, 2014	$	265,333		$	6.81		-		7.95
Exercisable at July 31, 2014	$	265,333		$	6.81		-		7.95

Options outstanding and exercisable as of July 31, 2014 as follows:

Exercise Price		Outstanding Number of Shares		Remaining Life		Exercisable Number of Shares
$	6.60		200,000		8.54		200,000
$	7.50		53,333		6.73		53,333
$	7.50		4,000		4.81		4,000
$	7.50		8,000		2.93		8,000
			265,333				265,333

Summary information regarding nonvested stock options as of July 31, 2013 is as follows:

Exercise Price		Outstanding Number of Shares		Remaining Life		Exercisable Number of Shares
$	6.60		200,000		9.54		-
$	7.50		265,333		7.73		212,267
$	7.50		20,000		3.93		20,000
$	7.50		8,000		5.81		8,000
$	7.50		18,667	Less than 1 year			18,667
			512,000				258,933

Summary information regarding nonvested stock options as of July 31, 2014 is as follows:

	Number of shares			Weighted average grant date fair value
Nonvested at July 31, 2013		253,067		$	7.41
Granted		-		$	-
Vested		(6,400	)	$	7.50
Forfeited		(246,667	)	$	7.50
Nonvested at July 31, 2014		-		$	-

Warrants

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 the father-in-law of Jeremy Driver, a former Director and our former Chief Executive Officer and the brother of our current CEO. 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, warrants to purchase 200,000 shares 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, warrants to purchase 200,000 shares with an exercise price of $7.50 and an expiration date of February 15, 2016 shall be exercisable (“Warrant C”). See Note 9 – Fair Value, for details regarding the fair value measurement and fair value methodology related to these warrants.

Summary information regarding common stock warrants issued and outstanding as of July 31, 2014, is as follows:

	Warrants			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (in years)
Outstanding at year ended July 31, 2012		1,252,152		$	7.74	$	-		2.83
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(15,193	)		28.02		-		-
Outstanding at year ended July 31, 2013		1,236,959		$	7.50	$	-		1.87
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(152,375	)		7.50		-		-
Outstanding at year ended July 31, 2014		1,084,584		$	7.50	$	-		1.04

Warrants outstanding and exercisable as of July 31, 2014:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	7.50		666,667	2 years or less		666,667
$	7.50		349,117	1 year or less		349,117
$	7.50		68,800	1 year or less		68,800
			1,084,584			1,084,584

Warrants outstanding and exercisable as of July 31, 2013:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	7.50		666,667	3 years or less		266,667
$	7.50		417,919	2 years or less		417,919
$	7.50		152,373	1 year or less		152,373
			1,236,959			836,959

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Net Proved Reserves) (Details)	12 Months Ended
	Jul. 31, 2014 MMcf	Jul. 31, 2013 MMcf
Reserve Quantities [Line Items]
Beginning Balance	16,688,590	23,067,460
Revisions of previous estimates	2,538,043	(5,834,587)
Sale of reserves in place	(636,437)	(8)
Production	(428,185)	(544,275)
Ending Balance	18,162,011	16,688,590
Proved developed producing	2,175,826	3,092,160
Proved developed non-producing	6,087,112	6,376,700
Proved undeveloped	9,899,073	7,219,730
Total Proved reserves	18,162,011	16,688,590
Oil [Member]
Reserve Quantities [Line Items]
Beginning Balance	659,700	1,388,250
Revisions of previous estimates	422,261	(667,307)
Sale of reserves in place	(17,750)	(1)
Production	(42,436)	(61,242)
Ending Balance	1,021,775	659,700
Proved developed producing	200,981	256,290
Proved developed non-producing	212,320	229,290
Proved undeveloped	608,474	174,120
Total Proved reserves	1,021,775	659,700
Gas [Member]
Reserve Quantities [Line Items]
Beginning Balance	12,730,390	14,737,960
Revisions of previous estimates	4,477	(1,830,745)
Sale of reserves in place	(529,937)	(2)
Production	(173,569)	(176,823)
Ending Balance	12,031,361	12,730,390
Proved developed producing	969,940	1,554,420
Proved developed non-producing	4,813,192	5,000,960
Proved undeveloped	6,248,229	6,175,010
Total Proved reserves	12,031,361	12,730,390

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Costs Incurred) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Property acquisition [Abstract]
Unproved	$ 1,232,815	$ 808,307
Proved	13	3,000
Exploration	238,112	404,265
Development	0	1,732,451
Cost recovery	(658,195)	(196,001)
Total costs incurred	812,745	2,752,022
Namibia [Member]
Property acquisition [Abstract]
Unproved	1,232,815	677,795
Proved	0	0
Exploration	173,299	35,860
Development	0	0
Cost recovery	0	0
Total costs incurred	1,406,114	713,655
Unites States [Member]
Property acquisition [Abstract]
Unproved	0	130,512
Proved	13	3,000
Exploration	64,813	368,405
Development	0	1,732,451
Cost recovery	(658,195)	(196,001)
Total costs incurred	$ (593,369)	$ 2,038,367

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Supplemental Oil and Gas Information (Unaudited) (Narrative) (Details)	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Average oil and gas price per barrel	100.11	92.52
Average gas price per MMbtu	4.10	3.51

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Additional Financial Statement Information (Tables)

12 Months Ended

Jul. 31, 2014

Additional Financial Statement Information [Abstract]

Schedule of Other Current Assets

Other current assets consisted of the following:

As of July July 31,	2014		2013
Prepaid letter of credit fees		92,763		93,362
Prepaid insurance		287,743		184,138
Other prepaid expenses		63,143		11,101
Cash call paid to operator		-		24,225
Prepaid land use fees		-		28,728
Accrued interest income		2,671		4,388
Other current assets		446,320		345,942

Schedule of Property and Equipment

Property and equipment consisted of the following:

As of July 31,		2014			2013
Furniture and fixtures	5 years	$	24,085		$	8,814
Marine vessels	5 years		109,742			17,614
Vehicles	5 years		40,496			65,807
Computer equipment and software	2 years		126,143			82,466
Leasehold improvements	2 years		2,087			-
Other depreciable property	2 years		-			297
Total property and equipment			302,553			174,998
Less accumulated depreciation			(135,590	)		(116,945	)
Net book value		$	166,963		$	58,053
Depreciation expense		$	36,894		$	61,215

Schedule of Accounts Payables and Accrued Expenses

Accounts payable and accrued expenses consisted of the following:

As of July 31,	2014		2013
Trade payables		2,567,324		2,503,820
Accrued payroll		43,578		151,577
Accrued interest and fees		37,853		500
Revenue payable		5,790		4,717
Local taxes and royalty payable		111,699		128,470
Federal and state income taxes payable		29,431		27,000
Total accounts payable and accrued expenses		2,795,675		2,816,084

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Capital Stock, Schedule of Nonvested Share Activity (Details) (USD $)	12 Months Ended
	Jul. 31, 2014
Number of shares [Abstract]
Nonvested at July 31, 2013 (in shares)	253,067
Granted (in shares)	0
Vested (in shares)	(6,400)
Forfeited (in shares)	(246,667)
Nonvested at July 31, 2014 (in shares)	0
Weighted average grant date fair value [Abstract]
Nonvested at July 31, 2013 (in dollars per shares)	$ 7.41
Granted (in dollars per shares)	$ 0
Vested (in dollars per shares)	$ 7.50
Forfeited (in dollars per shares)	$ 7.50
Nonvested at July 31, 2014 (in dollars per shares)	$ 0

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Subsequent Events

12 Months Ended

Jul. 31, 2014

Subsequent Events [Abstract]

Subsequent Events

Note 15 – Subsequent Events

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 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.

Effective November 6, 2014, settlement negotiations with respect to the ERG Resources lawsuit have been concluded. Galveston Bay Energy has paid $35,000 in cash and Hydrocarb Energy will issue 65,000 shares in restricted common stock to settle. More than this amount has been accrued previously and no further adjustments will be made to our financial statements.

Pursuant to the Credit Agreement, we have the right, at any time prior to the one year anniversary of the Credit Agreement, to borrow up to an additional $1,000,000 under the Credit Agreement (the “Additional Loan”), subject to certain pre-requisites and requirements as set forth in the Credit Agreement, including, but not limited to us raising $750,000 through the sale of equity subsequent to the closing of the transactions contemplated by the Credit Agreement (which we agreed to obtain within 150 days of the date of the Credit Agreement).  We also agreed to pay a 2% Structuring Fee on the Additional Loan. The proceeds of the Additional Loan may only be used for the Oil and Gas Activities.

The amount owed pursuant to the Notes (and any amount borrowed pursuant to the Additional Loan) is guaranteed by our wholly-owned subsidiary, Hydrocarb Corporation (“HC”) and its subsidiaries, and our other wholly-owned subsidiaries and is secured by a first priority security interest in substantially all of our assets (including, but not limited to the securities of our subsidiaries and HC and its subsidiaries) evidenced by a Guarantee and Collateral Agreement, various pledge agreements and a deed of trust providing the Agent, as agent for the Lenders, a security interest over our oil and gas assets and rights.

The Notes do not accrue any interest for the first nine months after their issuance date (August 15, 2014), provided thereafter they accrue interest at the rate of (a) 16% per annum where the average net monthly oil and gas production revenues of Galveston Bay Energy LLC, our wholly-owned subsidiary, for the trailing three month period (the “Trailing Three Month Revenues”) is less than $900,000; or (b) 14% per annum, where the Trailing Three Month Revenues are equal to or greater than $900,000, payable monthly in arrears through the maturity date of such Notes, August 15, 2016.  The Additional Loan, if any, will bear interest at the rate of 14% per annum, payable monthly in arrears, and will have the same maturity date as the Notes.  Upon the occurrence of an event of default, the Notes (and any amount outstanding under the Additional Loan) will bear interest at the rate of 24% per annum until paid in full.

Pursuant to the Credit Agreement, we agreed to issue the Lenders their pro rata share of (a) 60,000 restricted shares of common stock on the effective date of the Credit Agreement, August 15, 2014 (the “Effective Date”); (b) 32,500 restricted shares in the event any amount of the Loans (or other obligations outstanding under agreements entered into in connection with the Loans, the “Loan Documents”) are outstanding on the 12 month anniversary of the Effective Date; (c) 32,500 restricted shares in the event any amount is outstanding under the Loan Documents on the 18 month anniversary of the Effective Date; and (d) 25,000 restricted shares in the event any amount is outstanding under the Loan Documents on the 21 month anniversary of the Effective Date.  The shares are to be 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.

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.

The Credit Agreement includes customary events of default for facilities of a similar nature and size as the Credit Agreement, including, but not limited to, if any breach or default occurs under the Loan Documents, the failure of the Company to pay any amount when due under the Loan Documents, if the Company (or its subsidiaries) is subject to any judgment in excess of $250,000 which is not discharged or stayed within 30 days, or if a change in control of the Company, any subsidiary or any guarantor should occur, defined for purposes of the Credit Agreement as any transfer of 25% or more of the voting stock of such entity.

Subsequent to the issuance of the original Annual Report on Form 10-K, it was determined that our subsidiary, Otaiba Hydrocarb LLC in Abu Dhabi, United Arab Emirates, would be shut down. All expenses of operating have been realized on an ongoing basis, so the accounting effect of this shutdown is immaterial.

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Oil and Gas Properties (Tables)

12 Months Ended

Jul. 31, 2014

Oil and Gas Properties [Abstract]

Schedule of Oil and Natural Gas Properties

Oil and natural gas properties consisted of the following:

For the year ended July 31,	2014			2013
Evaluated Properties
Costs subject to depletion	$	19,153,125		$	19,857,842
Accumulated impairment		(373,335	)		(373,335	)
Accumulated depletion		(3,491,420	)		(2,617,478	)
Total evaluated properties		15,288,370			16,867,029
Unevaluated properties		2,119,769			1,124,805
Net oil and gas properties	$	17,408,139		$	17,991,834

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Capital Stock, Options Granted (Details) (USD $)	1 Months Ended		12 Months Ended				1 Months Ended	12 Months Ended
	Oct. 31, 2013	Aug. 31, 2013	Jul. 31, 2014		Jul. 31, 2013		Feb. 28, 2013 Person	Jul. 31, 2011 Person	Jul. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options vested (in shares)	53,333
Fair value of options vested	$ 810,738
Assumptions used in estimating fair value of options [Abstract]
Risk free interest rate (in hundredths)	2.09%	2.01%
Dividend yield (in hundredths)	0.00%	0.00%
Volatility factor (in hundredths)	117.31%	144.01%
Expected life	6 years 6 months	6 years 6 months
Information about options granted to non-employees under stock incentive plans [Abstract]
Compensation expense recognized			1,757,399		933,126
Options [Roll Forward]
Outstanding, beginning balance (in shares)		512,000	512,000
Outstanding, ending balance (in shares)			265,333		512,000
Exercisable, ending balance (in shares)			265,333		258,933
Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate number of options granted (in shares)							200,000
Weighted average exercise price of options granted (in dollars per share)							$ 6.60
Vesting period							10 years
Options granted to number of directors and employee							3
Vesting percentage of options after each six months (in hundredths)							20.00%
Period in which vesting of options should be complete							30 months
Fair value of options granted							1,196,589
Information about options granted to non-employees under stock incentive plans [Abstract]
Weighted average exercise price of options granted (in dollars per share)							$ 6.60
Weighted Average Exercise Price [Roll Forward]
Granted (in dollars per share)							$ 6.60
Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate number of options granted (in shares)								86,667
Weighted average exercise price of options granted (in dollars per share)								$ 7.50
Vesting period								10 years
Options granted to number of directors and employee								5
Vesting percentage of options after each six months (in hundredths)								20.00%
Period in which vesting of options should be complete								30 months
Unrecognized compensation cost related to stock options								0
Information about options granted to non-employees under stock incentive plans [Abstract]
Weighted average exercise price of options granted (in dollars per share)								$ 7.50
Weighted Average Exercise Price [Roll Forward]
Granted (in dollars per share)								$ 7.50
Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price of options granted (in dollars per share)			$ 0		$ 6.60
Assumptions used in estimating fair value of options [Abstract]
Risk free interest rate, minimum (in hundredths)				[1]	1.11%
Risk free interest rate, maximum (in hundredths)				[1]	2.00%
Dividend yield (in hundredths)			0.00%		0.00%
Volatility factor, minimum (in hundredths)				[1]	140.30%
Volatility factor, maximum (in hundredths)				[1]	144.00%
Expected life			0 years	[1]	6 years 6 months
Information about options granted to non-employees under stock incentive plans [Abstract]
Number of options granted (in shares)			0		200,000
Weighted average exercise price of options granted (in dollars per share)			$ 0		$ 6.60
Options [Roll Forward]
Outstanding, beginning balance (in shares)		512,000	512,000		348,000
Granted (in shares)			0		200,000
Exercised (in shares)			0		0
Expired or forfeited (in shares)			(246,667)		(36,000)
Outstanding, ending balance (in shares)			265,333		512,000				348,000
Exercisable, ending balance (in shares)			265,333
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)		6.81	$ 6.81		$ 7.50
Granted (in dollars per share)			$ 0		$ 6.60
Exercised (in dollars per share)			$ 0		$ 0
Expired or forfeited (in dollars per share)			$ 7.50		$ 7.50
Outstanding, ending balance (in dollars per share)			$ 6.81		$ 6.81				$ 7.50
Exercisable, ending balance (in dollars per share)			$ 6.81
Aggregate intrinsic value, beginning balance		0	0		0
Aggregate intrinsic value, ending balance			0		0				0
Aggregate intrinsic value, Exercisable			0
Weighted average remaining contractual life, beginning balance			7 years 11 months 12 days		7 years 11 months 23 days				7 years 2 months 19 days
Weighted average remaining contractual life, ending balance			7 years 11 months 12 days		7 years 11 months 23 days				7 years 2 months 19 days
Weighted average remaining contractual life, Exercisable			7 years 11 months 12 days
Stock Option [Member] | Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options vested (in shares)		13,333	666,666
Fair value of options vested		16,184
Stock Option [Member] | Non Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price of options granted (in dollars per share)				[1]	$ 6.60
Unrecognized compensation cost related to stock options			0
Information about options granted to non-employees under stock incentive plans [Abstract]
Number of options granted (in shares)			0		200,000
Compensation expense recognized	60,622		887,544		679,174
Weighted average exercise price of options granted (in dollars per share)				[1]	$ 6.60
Options [Roll Forward]
Granted (in shares)			0		200,000
Weighted Average Exercise Price [Roll Forward]
Granted (in dollars per share)				[1]	$ 6.60
Stock Option [Member] | Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price of options granted (in dollars per share)				[1]		[1]
Unrecognized compensation cost related to stock options			0		0
Information about options granted to non-employees under stock incentive plans [Abstract]
Number of options granted (in shares)			0		0
Compensation expense recognized			$ 56,028		$ 253,952
Weighted average exercise price of options granted (in dollars per share)				[1]		[1]
Options [Roll Forward]
Granted (in shares)			0		0
Weighted Average Exercise Price [Roll Forward]
Granted (in dollars per share)				[1]		[1]
2013 Stock Incentive Plan [Member]
Assumptions used in estimating fair value of options [Abstract]
Expected life			4 years 6 months

[1] N/A

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Oil and Gas Properties (Schedule of Oil and Gas Properties) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Evaluated Properties [Abstract]
Costs subject to depletion	$ 19,153,125	$ 19,857,842
Accumulated impairment	(373,335)	(373,335)
Accumulated Depletion	(3,491,420)	(2,617,478)
Total evaluated properties	15,288,370	16,867,029
Unevaluated properties	2,119,769	1,124,805
Net capitalized cost	$ 17,408,139	$ 17,991,834

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CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $)	Common Stock [Member] HCN [Member]	Common Stock [Member] HEC [Member]	Preferred Stock [Member] HCN [Member]	Preferred Stock [Member] HEC [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Other Comprehensive Income [Member]	Stock Subscription Receivable [Member]	Accumulated Deficit [Member]	Total
Balance at Jul. 31, 2012	$ 0	$ 3,597	$ 0	$ 0	$ 38,342,757	$ 0	$ (743,082)	$ 0	$ (25,927,122)	$ 11,676,150
Balance, (in shares) at Jul. 31, 2012	0	3,597,071	0	0
Acquisition		830			35,395,970					35,396,800
Acquisition, (in shares)		830,000
Issuance of HCN preferred stock			1,690,000							1,690,000
Issuance of HCN preferred stock (in shares)			4,225
HCN purchase of HEC common stock						(822,250)				(822,250)
Share-based compensation:
Amortization of fair value of stock options					933,126					933,126
Warrants granted to related party					196,384					196,384
Expiration of derivative warrant liability					269,164					269,164
Unrealized loss on available for sale securities							743,082			743,082
Dividend on HCN preferred stock									(69,920)	(69,920)
Net loss attributable to HEC									(37,525,733)	(37,525,733)
Balance at Jul. 31, 2013	0	4,427	1,690,000	0	75,137,401	(822,250)	0	0	(63,522,775)	12,486,803
Balance, (in shares) at Jul. 31, 2013	0	4,427,071	4,225	0						4,427,071
Issuance of HCN preferred stock	6,560				24,511					31,071
Issuance of HCN preferred stock (in shares)	6,559,257
Issuance of HCN preferred stock to settle debt and accounts payable			1,585,200							1,585,200
Issuance of HCN preferred stock to settle debt and accounts payable (in shares)			3,963
HCN sale of HEC common stock for receivable					177,750	822,250		(1,000,000)		0
HCN sale of HEC common stock for receivable					(1,729,688)	3,589,567		(1,859,879)		0
HEC preferred stock exchanged in connection with HCN acquisition			(3,275,200)	3,275,200						0
HEC preferred stock exchanged in connection with HCN acquisition (in shares)			(8,188)	8,188
HEC common stock exchanged in connection with HCN acquisition	(6,560)	8,397			(1,837)					0
HEC common stock exchanged in connection with HCN acquisition (in shares)	(6,559,257)	8,396,667
HEC Common stock issued to satisfy contingently-issued rights from NEI Acquisition		7,470			(7,470)					0
HEC Common stock issued to satisfy contingently-issued rights from NEI Acquisition (in shares)		7,470,000
HEC common stock issued to settle debt		620			3,588,947	(3,589,567)				0
HEC common stock issued to settle debt (in shares)		619,960
Deemed Dividend on Preferred Stock					949,808					949,908
Deemed Dividend on Preferred Stock					(949,808)					(949,908)
Share-based compensation:
Amortization of fair value of stock options					943,572					943,572
Warrants granted to related party					6,754					6,754
Stock issued to employees and directors		168			813,659					813,827
Stock issued to employees and directors (in shares)		167,904
Expiration of derivative warrant liability										0
Dividend on HCN preferred stock									(34,254)	(34,254)
Cash collection on stock subscription receivable								675,000		675,000
Net loss attributable to HEC									(6,549,322)	(6,549,322)
Balance at Jul. 31, 2014	$ 0	$ 21,082	$ 0	$ 3,275,200	$ 78,953,599	$ 0	$ 0	$ (2,184,879)	$ (70,106,351)	$ 9,958,651
Balance, (in shares) at Jul. 31, 2014	0	21,081,602	0	8,188						21,081,602

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Available for Sale Securities

12 Months Ended

Jul. 31, 2014

Available for Sale Securities [Abstract]

Available for Sale Securities

Note 4 – Available for Sale Securities

During the year ended July 31, 2012, we purchased securities at a market price of $702,959 and reclassified $6,383 unrealized loss from other comprehensive loss into earnings.

During September 2012, we received cash proceeds of $145,237 from sales of securities with a cost basis of $607,201; thus, we had a realized loss on sale of available for sale securities of $461,964. In October 2012, we recognized an other than temporary impairment of $275,327 resulting in a new cost basis in the stock of $174,000.

During December 2012, we received cash proceeds of $142,637 from sales of securities with a cost basis of $198,593; thus, we had a realized loss on sale of available for sale securities of $55,956. We reclassified $743,082 unrealized loss from other comprehensive loss into earnings in conjunction with these sales and the impairment.

As of July 31, 2014 and July 31, 2013, we do not hold any available for sale securities.

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Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Jul. 31, 2014 LetterofCredit	Jul. 31, 2013	May 31, 2012
Commitments And Contingencies [Line Items]
Contingency accrued		$ 232,974
Cash settlement to be paid by Galveston Bay	35,000
Stock settlement to be paid by Hydrocarb	65,000
Cost of renewal easements	400,000
Rent expense	186,463	211,346
Monthly compression and handling fees	1,000
Number of letters of credit in favor of the Railroad Commission of Texas	2
Debt instrument, face amount			18,375
Schedule of prepaid balances [Abstract]
Prepaid letter of credit fees	101,251	101,850
Amortization	(8,488)	(8,488)
Net prepaid letter of credit fees	92,763	93,362
Letter of Credit One [Member]
Commitments And Contingencies [Line Items]
Debt instrument, face amount	6,610,000
Debt instrument, fee percentage (in hundredths)	1.50%
Letter Of Credit Two [Member]
Commitments And Contingencies [Line Items]
Debt instrument, face amount	120,000
Debt instrument, fee percentage (in hundredths)	1.50%
Houston, Texas Office [Member]
Commitments And Contingencies [Line Items]
Operating lease, term of lease	3 years
Operating lease, term of lease extension	3 years
Monthly rental payments	6,406
Monthly rental payments, year two	6,673
Monthly rental payments, year three	6,940
Accounts payable and accrued expenses [Member]
Commitments And Contingencies [Line Items]
Environmental remediation expense	150,000	150,000
Minimum [Member]
Commitments And Contingencies [Line Items]
Loss contingency, estimate	150,000
Maximum [Member]
Commitments And Contingencies [Line Items]
Loss contingency, estimate	$ 900,000

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Standardized Measure) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Future cash inflows	$ 159,283,690	$ 113,603,450
Future production costs	(54,437,098)	(55,897,070)
Future development costs	(43,054,816)	(41,794,284)
Future income tax expenses	(21,627,122)	(5,569,234)
Future net cash flows	40,164,654	10,342,862
10% annual discount for estimated timing of cash flows	(15,807,988)	(3,990,069)
Future net cash flows at end of year	$ 24,356,666	$ 6,352,793

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Asset Retirement Obligation (Tables)

12 Months Ended

Jul. 31, 2014

Asset Retirement Obligation [Abstract]

Reconciliation of Asset Retirement Obligation

The following is a reconciliation of our asset retirement obligation liability as of July 31, 2014 and 2013, respectively.

	2014			2013
czReconciliation of asset retirement obligation balance
Liability for asset retirement obligation, beginning of period	$	10,933,398		$	9,382,933
Asset retirement obligations sold		(33,195	)		(438	)
Asset retirement obligations incurred on properties drilled		-			26,500
Accretion		1,043,928			1,056,508
Revisions in estimated cash flows		(104,237	)		786,120
Costs incurred		(123,664	)		(318,225	)
Liability for asset retirement obligation, end of period	$	11,716,230		$	10,933,398
Current portion of asset retirement obligation	$	1,133,690		$	724,374
Noncurrent portion of asset retirement obligation		10,582,540			10,209,024
Total liability for asset retirement obligation	$	11,716,230		$	10,933,398

Estimated Timing of asset retirement obligation payments

Estimated Timing of asset retirement obligation payments:

Fiscal Year	Pipelines		Easements		Wellbores		Facilities		Total
2015	$	126,290	$	-	$	997,400	$	10,000	$	1,133,690
2016	$	60,000	$	27,516	$	639,725	$	-	$	727,241
2017	$	99,938	$	66,006	$	191,476	$	837,436	$	1,194,856
2018	$	55,040	$	14,475	$	548,700	$	-	$	618,215
2019	$	52,621	$	10,429	$	572,337	$	221,757	$	857,144
2020 to 2024	$	980,713	$	193,283	$	2,269,781	$	848,211	$	4,291,988
2025 to 2029	$	236,898	$	67,089	$	1,356,391	$		$	1,660,378
2030 to 2034	$	44,439	$	145,197	$	143,578	$	899,504	$	1,232,718
Thereafter	$	-	$	-	$	-	$	-	$	-
Total	$	1,655,939	$	523,995.06	$	6,719,388	$	2,816,908	$	11,716,230

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Acquisitions, Namibia Exploration, Inc. (Details) (USD $)	0 Months Ended		12 Months Ended
	Dec. 09, 2013	Sep. 06, 2012	Jul. 31, 2014	Jul. 31, 2013	Sep. 30, 2012	Sep. 06, 2012
Business Acquisition [Line Items]
Acquisition-related costs - related party			$ 0	$ 34,834,752
Ownership percentage (in hundredths)	39.00%		90.00%
Stock issued during period for acquisition				35,396,800
Namibia Exploration, Inc. [Member]
Business Acquisition [Line Items]
Stock issued during period for acquisition, shares (in shares)		8,396,667
Acquisition-related costs - related party		34,834,752
Amount of farm-in fee paid by original owners for payment of concession		2,400,000
Farm in fee of concession property payable period		2 years
Cost basis in working interest in oil and gas property		562,048	562,048	562,048
Ownership percentage (in hundredths)		39.00%				39.00%
Cost responsibility percentage (in hundredths)		43.33%			43.33%	43.33%
Contingent shares to be issued upon achievement of milestone one (in shares)		830,000				830,000
Period within which milestones must be reached after the closing of acquisition		10 years
Contingent shares to be issued upon achievement of milestone two (in shares)		2,490,000				2,490,000
Contingent shares to be issued upon achievement of milestone three (in shares)		4,150,000				4,150,000
The minimum ten day volume-weighted average market capitalization to achieve milestone one		82,000,000				82,000,000
Volume-weighted average market capitalization period		10 days
The minimum ten day volume-weighted average market capitalization to achieve milestone two		196,000,000				196,000,000
The minimum ten day volume-weighted average market capitalization to achieve milestone three		434,000,000				434,000,000
Total consulting fee per consulting services agreement		2,400,000				2,400,000
Fair value of contingent equity grant		29,212,000
Liabilities assumed in business acquisition		1,837,952				1,837,952
Stock issued during period for acquisition		$ 3,784,800
Shares reserved for issuance to certain stock holders with certain rights (in shares)	7,470,000
Namibia Exploration, Inc. [Member] | Hydrocarb Namibia [Member]
Business Acquisition [Line Items]
Ownership percentage (in hundredths)		90.00%				90.00%
Cost responsibility percentage (in hundredths)		100.00%				100.00%
Namibia Exploration, Inc. [Member] | Market Approach Valuation Technique [Member]
Business Acquisition [Line Items]
Fair value measurement discount rate (in hundredths)		75.00%
Namibia Exploration, Inc. [Member] | Income Approach Valuation Technique [Member]
Business Acquisition [Line Items]
Fair value measurement discount rate (in hundredths)		25.00%

XML

Additional Financial Statement Information

12 Months Ended

Jul. 31, 2014

Additional Financial Statement Information [Abstract]

Additional Financial Statement Information

Note 14 – Additional Financial Statement Information

Other receivables

Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate.  We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. As of July 31, 2014 and 2013, we have reserved $70,742 and $58,585, respectively, for potentially uncollectable other receivables.

Other current assets

Other current assets consisted of the following:

As of July July 31,	2014		2013
Prepaid letter of credit fees		92,763		93,362
Prepaid insurance		287,743		184,138
Other prepaid expenses		63,143		11,101
Cash call paid to operator		-		24,225
Prepaid land use fees		-		28,728
Accrued interest income		2,671		4,388
Other current assets		446,320		345,942

Property and Equipment

Property and equipment consisted of the following:

As of July 31,		2014			2013
Furniture and fixtures	5 years	$	24,085		$	8,814
Marine vessels	5 years		109,742			17,614
Vehicles	5 years		40,496			65,807
Computer equipment and software	2 years		126,143			82,466
Leasehold improvements	2 years		2,087			-
Other depreciable property	2 years		-			297
Total property and equipment			302,553			174,998
Less accumulated depreciation			(135,590	)		(116,945	)
Net book value		$	166,963		$	58,053
Depreciation expense		$	36,894		$	61,215

Accounts payable and accrued expenses

Accounts payable and accrued expenses consisted of the following:

As of July 31,	2014		2013
Trade payables		2,567,324		2,503,820
Accrued payroll		43,578		151,577
Accrued interest and fees		37,853		500
Revenue payable		5,790		4,717
Local taxes and royalty payable		111,699		128,470
Federal and state income taxes payable		29,431		27,000
Total accounts payable and accrued expenses		2,795,675		2,816,084