HOLLOMAN ENERGY CORP - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - HOLLOMAN ENERGY CORP	Financial_Report.xls
EX-31.2 - CFO CERTIFICATION - HOLLOMAN ENERGY CORP	henc_ex312.htm
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EX-32 - 906 CERTIFICATIONS - HOLLOMAN ENERGY CORP	henc_ex32.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

———————

FORM 10-Q

———————

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

For the quarterly period ended March 31, 2013

¨ TRANSITION REPORT PURSUANT TO 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________ to ________

Commission File Number: 000-52419

HOLLOMAN ENERGY CORPORATION

(Exact Name of Issuer as Specified in Its Charter)

Nevada		77-0643398
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

333 North Sam Houston Parkway East, Suite 600, Houston, Texas 77060

(Address of Issuer's Principal Executive Offices) (Zip Code)

Issuer’s telephone number: (281) 260-0193

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

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

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

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	þ
(Do not check if a smaller reporting company)

Indicate by check mark whether the Registrant is a shell company (as defined in Exchange Act Rule 12b-2 of the Exchange Act). Yes ¨ No þ

Class of Stock		No. Shares Outstanding		Date
Common		110,313,011		May 14, 2013

PART I FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

HOLLOMAN ENERGY CORPORATION

(An Exploration Stage Company)

CONSOLIDATED BALANCE SHEETS

	March 31, 2013			December 31, 2012
	(Unaudited)
ASSETS

ASSETS
Cash	$	878,354		$	1,009,882
Other receivable		1,475			1,468
Prepaid expenses		8,498			6,657
Current Assets		888,327			1,018,007

Oil and gas properties, full cost method, unproven		16,643,355			16,629,162
Total Assets	$	17,531,682		$	17,647,169


LIABILITIES AND STOCKHOLDERS' EQUITY

LIABILITIES
Accounts payable and accrued liabilities	$	184,004		$	212,769
Note payable		1,000,000			1,000,000
Current Liabilities		1,184,004			1,212,769

Deferred tax liability		4,934,365			4,909,617
Total Liabilities		6,118,369			6,122,386

STOCKHOLDERS' EQUITY
Authorized:
10,000,000 preferred shares, par value $0.001 per share
150,000,000 common shares, par value $0.001 per share
Issued and outstanding :
110,313,011 common shares (110,276,978 at December 31, 2012)		110,313			110,277
Additional paid in capital		25,843,508			25,828,544
Accumulated other comprehensive loss		(9,147	)		(8,898	)
Deficit accumulated during the exploration stage		(14,531,361	)		(14,405,140	)
Total Stockholders' Equity		11,413,313			11,524,783

Total Liabilities and Stockholders' Equity	$	17,531,682		$	17,647,169

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

HOLLOMAN ENERGY CORPORATION

(An Exploration Stage Company)

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Cumulative results from May 5, 2006 (Inception)			Three Months Ended March 31,
	to March 31, 2013			2013			2012

CONTINUING OPERATIONS
Expenses
Consulting	$	1,631,829		$	15,000		$	15,000
Foreign exchange loss		1,027,124			24,748			105,956
Gain on settlement of debt		(40,026	)		-			-
Management and directors' fees		1,388,948			35,078			42,900
Stock-based compensation expense		2,511,212			-			-
Office, travel and general		860,157			35,608			25,627
Professional fees		763,819			4,550			2,907
Salaries, wages, and benefits		86,666			-			-
Bad debt expense		3,395			-			-
Interest expense		11,237			11,237			-
Total Expenses		(8,244,361	)		(126,221	)		(192,390	)

Oil and gas property impairment		(7,396,207	)		-			-
Deferred income tax recovery		2,244,107			-			-
Other Income		535,869			-			107,160
Loss from Continuing Operations		(12,860,592	)		(126,221	)		(85,230	)

DISCONTINUED OPERATIONS
Loss from discontinued operations		(2,454,637	)		-			-
Gain on disposal of Endeavor		783,868			-			-
Loss from Discontinued Operations		(1,670,769	)		-			-

NET LOSS	$	(14,531,361	)	$	(126,221	)	$	(85,230	)

Foreign currency translation		(9,147	)		(249	)		2,030

COMPREHENSIVE LOSS	$	(14,540,508	)	$	(126,470	)	$	(83,200	)

BASIC AND DILUTED NET LOSS FROM
CONTINUING OPERATIONS PER COMMON SHARE				$	(0.00	)	$	(0.00	)

BASIC AND DILUTED NET LOSS FROM DISCONTINUED
OPERATIONS PER COMMON SHARE				$	(0.00	)	$	(0.00	)

BASIC AND DILUTED NET LOSS
PER COMMON SHARE				$	(0.00	)	$	(0.00	)

WEIGHTED AVERAGE NUMBER OF BASIC AND
DILUTED COMMON SHARES OUTSTANDING					110,277,378			108,998,392

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

HOLLOMAN ENERGY CORPORATION

(A Exploration Stage Company)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Cumulative results from May 5, 2006 (Inception)			Three Months Ended March 31,
	to March 31, 2013			2013			2012

OPERATING ACTIVITIES
Net loss	$	(14,531,361	)	$	(126,221	)	$	(85,230	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Cash used by discontinued operations		1,729,701			-			-
Gain on disposal of Endeavor		(783,868	)		-			-
Gain from settlement of indebtedness		(65,026	)		-			-
Stock-based compensation and fee payments		3,339,212			-			-
Unrealized foreign exchange loss		977,517			24,499			107,222
Impairment of oil and gas properties (net of tax recovery)		5,152,100			-			-
Changes in non-cash working capital items
Other receivable		(1,475	)		(7	)		(502	)
Prepaid expenses		(8,498	)		(1,841	)		(3,887	)
Accounts payable and accrued liabilities		483,377			(27,958	)		(201	)
Contract advances		131,190			-			(7,160	)
Cash provided by (used in) operating activities		(3,577,131	)		(131,528	)		10,242

INVESTING ACTIVITIES
Investing activities from discontinued operations		(1,447,739	)		-			-
Oil and gas expenditures		(1,406,985	)		-			(3,509	)
Oil and gas expenditures recovered from partners		37,340			-			-
Cash acquired on acquisition		12,696			-			-
Deposit on acquisition		(639,487	)		-			-
Deposits		-			-			-
Cash used in investing activities		(3,444,175	)		-			(3,509	)

FINANCING ACTIVITIES
Financing activities from discontinued operations		2,000,261			-			-
Common stock issued for cash		3,505,001			-			-
Loans payable		1,050,567			-			-
Related party repayments		(100,000	)		-			(100,000	)
Proceeds from related parties		1,443,831			-			100,000
Cash provided by financing activities		7,899,660			-			-

CHANGE IN CASH		878,354			(131,528	)		6,733
CASH, BEGINNING		-			1,009,882			11,637

CASH, ENDING	$	878,354		$	878,354		$	18,370

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest	$	11,098		$	-		$	-

NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures in oil and gas properties	$	-		$	14,193		$	17,733

NON-CASH FINANCING ACTIVITIES:
Shares issued for management fees	$	231,750		$	-		$	-
Shares issued for services	$	440,000		$	15,000		$	15,000
Shares issued on conversion of liabilities	$	2,661,879		$	-		$	-
Shares issued for property acquired	$	15,903,000		$	-		$	-

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

HOLLOMAN ENERGY CORPORATION

(An Exploration Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

Unaudited Interim Consolidated Financial Statements

The unaudited interim consolidated financial statements of Holloman Energy Corporation (the “Company”) have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They do not include all information and footnotes required by GAAP for complete financial statements. However, except as disclosed herein, there have been no material changes in the information disclosed in the notes to the consolidated financial statements for the year ended December 31, 2012 included in the Company’s Annual Report on Form 10-K filed with the SEC. The unaudited interim consolidated financial statements should be read in conjunction with those consolidated financial statements and footnotes included in the Form 10-K. In the opinion of management, all adjustments considered necessary for fair presentation, consisting solely of normal recurring adjustments, have been made. Operating results for the three month period ended March 31, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

Recent Accounting Pronouncements

The Company has reviewed recently issued accounting pronouncements and plans to adopt those that are applicable to it. It does not expect the adoption of these pronouncements to have a material impact on its consolidated financial position, results of operations or cash flows.

2. OIL AND GAS PROPERTIES

The Company currently holds working interests of 66.67% in two onshore Petroleum Exploration Licenses (PELs) in Australia. PEL 112 is comprised of 2,196 square kilometers (542,643 gross acres). PEL 444 is comprised of 2,358 square kilometers (582,674 gross acres). Both licenses are located on the southwestern flank of the Cooper Basin in the State of South Australia. The Company’s oil and gas properties are unproven. As such, the costs capitalized in connection with those properties are not currently subject to depletion.

Effective May 11, 2012, the Company entered into a definitive Oil and Gas Farm-In Agreement with Terra Nova and its wholly owned subsidiary Terra Nova Resources Inc. (“Terra Nova”), Australian-Canadian Oil Royalties Ltd. (“ACOR”) and Eli Sakhai (“Sakhai”) on PEL 112 and PEL 444 (the “Agreement”). The Agreement provides terms under which Terra Nova may earn up to a 55% undivided working interest in PEL 112 and PEL 444 (the “Farm-In Interest”).

During 2012, in connection with the Agreement, Terra Nova paid the Company non-refundable cash fees totaling $350,000, and 666,670 shares of its common stock with a fair market value of $193,334. The shares were measured at fair market value on a non-recurring basis using quoted market prices, and are categorized as a Level 1 fair value measurement under ASC Topic 820. The Company agreed to provide ACOR and Sakhai a full accounting of its use of the cash fees, and to share with ACOR and Sakhai, any excess of the cash fees over the transaction costs it incurred in connection with the Agreement. As a result of its analysis, the Company identified a total of $54,719 in excess fees to be refunded to ACOR and Sakhai. Of that amount, the Company has withheld $37,340 as a recovery of exploration costs payable to it by ACOR and Sakhai.

To earn the entire Farm-In Interest, Terra Nova is required to fund exploration and development expenditures (the “Earning Obligations”) totaling at least AUD$13,700,000 (USD$14,308,000) including:

●

AUD$4,700,000 (USD$4,968,000) which was placed in escrow during May 2012 for use in the completion of a seismic acquisition program sufficient to meet the minimum seismic acquisition requirements, and interpretation of the acquired data for PEL 112 and PEL 444 (earning a 20% working interest in each license);

●

AUD$4,500,000 (USD$4,670,000) which was placed in escrow on November 1, 2012 to secure Terra Nova’s obligation to sole fund the dry-hole costs of an initial three (3) well drilling program on either PEL 112 or PEL 444, provided that at least one well is drilled on each license (earning a working interest of 5.833% per well in each license, totaling a working interest of 17.5%); and

●

AUD$4,500,000 (USD$4,670,000) to be placed in escrow on or before 45 days following completion or abandonment of the third well in the initial well program, for use in funding the first AUD$4,500,000 in dry-hole costs of an optional three (3) well drilling program on either PEL 112 or PEL 444, provided that at least one well is drilled on each license (earning a working interest of 5.833% per well in each license, totaling a working interest of 17.5%).

Terra Nova will act as contract operator with respect to all seismic acquisition and drilling work contemplated by the Agreement.

Costs incurred in relation to the seismic earning obligations in excess of AUD$4,700,000, if any, shall be borne by Terra Nova, the Company, ACOR and Sakhai in accordance with their Working Interest percentages calculated as though Terra Nova had successfully completed its Earning Obligations and earned the entire Farm-In Interest.

Acquisition of 127 square kilometers of 3-D seismic data on PEL 112 began July 24, 2012 and was completed in late September 2012 which fulfilled the Company’s minimum work requirements for PEL 112 License Year Four. Geokinetics (Australia) Pty. Ltd. undertook the 3D seismic survey on the northern boundary of PEL 112 under the direction of Terra Nova. Four drill site targets were identified as a result of the interpretation of the seismic data acquired.

In the event Terra Nova elects to complete either or both of the first two wells drilled in connection with the initial three well drilling program, Terra Nova will pay 50% of the completion costs and the Company will pay the other 50% of the completion costs. In the event Terra Nova elects to complete the third well drilled in connection with the initial three well drilling program, or any well drilled in connection with the optional three well drilling program, Terra Nova will pay 50% of the completion costs, and the Company, ACOR and Sakhai will pay the other 50% of the completion costs in accordance with their working interest at the effective date of the Agreement.

In the event any well drilled in connection with either the initial or optional drilling programs is commercially viable, and Terra Nova elects to complete such well, Terra Nova is entitled to a preferential recovery of one hundred percent of the costs it has paid to drill and test that successful well. Terra Nova is entitled to 80% of production from that successful well until either that successful well has ceased production or Terra Nova has received net revenue equal to the reimbursable costs it has incurred.

Terra Nova will earn the Farm-In Interest in stages based upon successful completion of specific Earning Obligations. In each instance, the Company, ACOR and Sakhai will each contribute a portion of the working interest earned by Terra Nova. In the event Terra Nova earns the entire Farm-In Interest, the Company, ACOR and Sakhai will transfer to Terra Nova the following working interest percentages in both PEL 112 and PEL 444:

(a)	The Company will contribute an undivided 38.556% working interest in both PEL 112 and PEL 444 (resulting in a residual working interest position of 28.112% in each license);
(b)	ACOR will contribute an undivided 8.222% working interest in both PEL 112 and PEL 444; and
(c)	Sakhai will contribute an undivided 8.222% working interest in both PEL 112 and PEL 444.

During February 2013, Terra Nova delivered copies of the data acquired in connection with its acquisition of 127 square kilometers of a 3-D seismic data on PEL 112. As a result, Terra Nova has effectively completed its Earning Obligation with respect to PEL 112 seismic acquisition, and has earned an undivided 20% working interest in that license. The Company, ACOR and Sakhai will each contribute a portion of the working interest earned by Terra Nova as follows:

(a)	The Company will contribute an undivided 13.3334% working interest in PEL 112 resulting in a residual working interest position of 53.333% in that license;
(b)	ACOR will contribute an undivided 3.3333% working interest in PEL 112; and
(c)	Sakhai will contribute an undivided 3.3333% working interest in PEL 112.

As of March 31, 2013 the Company was processing the documents required to facilitate the transfer of the working interest earned by Terra Nova.

The Agreement may be terminated by any party upon the occurrence of an uncured breach of any material term. Terra Nova may terminate the Agreement any time before it has earned the Farm-In Interest upon providing written notice of such termination. In the event Terra Nova terminates the Agreement, it shall not be entitled to any interest in either PEL 112 or PEL 444 unless it has satisfied an Earning Obligation with respect to that license.

The Company requested, and was granted, an additional extension of time to complete its License Year Three minimum work requirement on PEL 444. As a result, the time frame for acquisition of a minimum of 200 kilometer of 2D seismic data was extended from January 11, 2013 to July 11, 2013, and the overall license term for PEL 444 was extended to July 11, 2015.

3. NOTE PAYABLE

On December 24, 2012 the Company entered into a Promissory Note with an unrelated party (“Lender”) under which it borrowed the principal amount of $1,000,000 (the “Note”). The Note bears interest at 4.5% per annum and provides for a penalty rate of interest of 10% per year on any unpaid principal which is not paid when due. The Note is payable upon demand of the Lender at any time, and may be prepaid by the Company without notice or penalty and has therefore been classified as a current liability at March 31, 2013.

For the three months ended March 31, 2013, the Company recognized $11,237 in interest expense on the Note, all of which was accrued and unpaid.

The Company’s controlling shareholder guaranteed the Company’s obligations under the Note.

4. OTHER INCOME

On March 23, 2012, Terra Nova paid the Company a fee of $100,000 in connection with the execution of a letter of intent. The fee paid by Terra Nova was fully earned upon receipt, was not repayable to Terra Nova under any circumstances, and was recognized as the primary component of other income during the three months ended March 31, 2012. No other income was earned during the three month period ended March 31, 2013.

5. COMMON STOCK AND STOCK – BASED COMPENSATION

The Company incurs $15,000 in administrative service fees payable to a wholly owned subsidiary of its controlling shareholder on a quarterly basis. During the three months ended March 31, 2013, the Company paid administrative fees totaling $15,000, using 36,033 shares of its common stock, at an approximate weighted average price of $0.416 per share.

At March 31, 2013 the Company had a total of 3,300,000 stock options outstanding with weighted average exercise prices and lives of $1.10 and 1.46 years, respectively.

FORWARD LOOKING STATEMENTS

The information contained in this Form 10-Q contains certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve risks and uncertainties, including among other things, statements regarding our capital needs, business strategy and expectations. Any statement which does not contain a historical fact may be deemed to be a forward-looking statement. In some cases, you can identify forward-looking statements by terminology such as "may", "will", "should", "expect", "plan", "intend", "anticipate", "believe", "estimate", "predict", "potential" or "continue", the negative of such terms or other comparable terminology. In evaluating forward looking statements, you should consider various factors outlined in our latest Form 10-K, filed with the U.S. Securities Exchange Commission (“SEC”) on April 1, 2013, and, from time to time, in other reports we file with the SEC. These factors may cause our actual results to differ materially from any forward-looking statement. We disclaim any obligation to publicly update these statements, or disclose any difference between our actual results and those reflected in these statements.

ITEM 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and related notes included as part of this report and our Form 10-K, for the year ended December 31, 2012 filed with the SEC on April 1, 2013.

We were incorporated on May 14, 2004 in Nevada. Between May 2004 and May 2007 we were relatively inactive. In May 2007, we directed our focus to the acquisition, exploration, and development of oil and gas properties. We are currently controlled by Holloman Corporation, a Texas corporation involved in the engineering and construction of pipelines and mid-stream gas processing facilities.

All of our exploration and development efforts are concentrated in Australia. We hold working interests in petroleum exploration licenses covering 4,554 square kilometers (1.125 million gross acres) located on the western flank of Australia’s Cooper Basin.

Effective May 11, 2012, we entered into a definitive Oil and Gas Farm-In Agreement with Terra Nova Energy Ltd., and its wholly owned subsidiary Terra Nova Resources Inc. (“Terra Nova”), which provides Terra Nova the right to earn up to a 55% undivided working interest in our Australian licenses in exchange for undertaking certain exploration obligations (the “Terra Nova Farm-In Agreement”).

We are an exploration stage company and did not participate in drilling any wells during the three years ended March 31, 2013.

As of May 14, 2013 we did not have any proven oil or gas reserves and we did not have any revenue.

Our Australian assets

In May 2007 we acquired a 62.5% working interest in an offshore Australian oil and gas exploration permit known as Victoria Permit 60 (“Vic P60”). We paid $639,487 in cash plus a 4.00% overriding royalty participation for this interest.

On November 21, 2007 we acquired Holloman Petroleum Pty. Ltd. (“Holloman Petroleum”) for 18,600,000 shares of our common stock. Holloman Petroleum’s assets consisted of working interests, varying between 37.5% and 100%, in seven oil and gas permits awarded by the Australian Government. These permits, one of which included the remaining 37.5% working interest in Vic P60, covered 8,087 square kilometers (1,998,348 acres) of land in the Cooper/Eromanga Basin and 2,589 square kilometers (639,755 acres) offshore in the Gippsland Basin and the Barrow Sub-Basin. We have subsequently relinquished the Vic P60 and Barrow Sub-Basin permits and consolidated two of our onshore licenses.

Onshore licenses – Cooper Basin

We currently hold working interests of 66.67% in two onshore Petroleum Exploration Licenses (PELs) in Australia. PEL 112 is comprised of 2,196 square kilometers (542,643 gross acres). PEL 444, which resulted from the consolidation of the PEL 108 and PEL 109 permits, is comprised of 2,358 square kilometers (582,674 gross acres). Both licenses are located on the southwestern flank of the Cooper Basin in the State of South Australia. We are obligated to pay royalties ranging from 3.96% to 4.63% on our revenues generated by operations on these licenses.

As of May 14, 2013 we were processing the documents required to facilitate the transfer of a 13.3334% working interest in PEL 112 earned by Terra Nova in connection with the Terra Nova Farm-In Agreement. After this transfer is complete, we will hold a residual working interest position of 53.333% in that license (see further details below).

The Department of Primary Industries and Resources of South Australia reports that the Cooper Basin has sourced over 4 billion barrels of oil and 5 trillion cubic feet of recoverable gas. It has in excess of 120,000 kilometers of 2-D seismic data and more than 1,800 wells in more than 65 oil and 20 gas fields. From January 2002 to February 2009, 129 exploration wells and 45 appraisal/development wells have been drilled by the new explorers in the Cooper Basin. Most have targeted oil; however both oil and gas have been discovered. The new entrants found new pools in 63 of these wells (49% technical success rate) and 55 were cased and suspended as future producers (43% commercial success rate). Our management believes that Australia provides a stable regulatory, tax and business environment in the oil and gas sector.

In June 2008 the Australian government extended the lease term and associated work programs for PEL 112 and PEL 444 by five years. Under Australian law, at the end of each five year term, one third of the area covered by a petroleum exploration license must be relinquished. During June 2008, we identified and relinquished one-third of the acreage covered by PEL 112 and PEL 444 to the Australian government.

Heavy rains beginning in February 2010 created wide scale flooding in the Cooper Basin. For nearly eighteen months, the inaccessibility of roads and facilities partially curtailed Cooper Basin oil production and resulted in a general contraction of exploration activity. We have applied for, and have been granted multiple license extensions on PEL 112 and PEL 444 from the Government of South Australia. Effective January 9, 2012, we were also granted a variation of license terms on PEL 112. Under the variation, the minimum work requirements for PEL 112 License Year Three (3) were exchanged for those of PEL 112 License Year Four (4). As a result, the timeframe for acquisition of 100 kilometers of 2D seismic data on that license was moved from January 10, 2012 to January 10, 2013. That seismic obligation was fulfilled in late September 2012.

During December 2012, we also applied for a suspension and extension of license terms on PEL 444. On January 3, 2013, we were granted a six-month extension such that the timeframe for acquisition of 200 kilometers of 2D seismic data on PEL 444 was moved from January 11, 2013 to July 11, 2013, and the overall license term for PEL 444 was extended to July 11, 2015.

To maintain our exploration rights in the Cooper/Eromanga Basin, the Australian Government requires that we fulfill the following minimum work commitments:

License	Description of Minimum Work Obligation	Date of Required Completion
PEL 112	Drill one well	January 10, 2014
PEL 444	Acquisition of new seismic data: 2D (200km)	July 11, 2013
PEL 444	Geological and geophysical studies	July 11, 2014
PEL 444	Drill one well	July 11, 2015

The farm-in agreement through which we hold our working interests in PEL 112 and PEL 444 also obligates us to fulfill the drilling commitment set forth in the licenses. Under Australian law, we are entitled to apply for one additional 5-year term on each of PEL 112 and PEL 444. We intend to make application for the additional 5-year term on PEL 112 during 2013.

Our oil and gas farm-in agreements and exploration activity

Cooper Basin farm-in agreements

Effective May 11, 2012, we entered the Terra Nova Farm-In Agreement with Terra Nova, Australian-Canadian Oil Royalties Ltd. (“ACOR”) and Eli Sakhai (“Sakhai”) on PELs 112 and 444. The Terra Nova Farm-In Agreement provides terms under which Terra Nova may earn a 55% undivided working interest in PEL 112 and PEL 444 (the “Farm-In Interest”).

●	AUD$4,700,000 (USD$4,968,000) which was paid and used in the completion of a seismic acquisition program sufficient to meet the minimum seismic acquisition requirements, and interpretation of the acquired data for PEL 112 and PEL 444 (earning a 20% working interest in each license);

●

Terra Nova will act as contract operator with respect to all seismic acquisition and drilling work contemplated by the Terra Nova Farm-In Agreement.

Costs incurred in relation to the seismic earning obligations in excess of AUD $4,700,000, if any, shall be borne by Terra Nova, ACOR, Sakhai and us in accordance with our Working Interest percentages calculated as though Terra Nova had successfully completed its Earning Obligations and earned the entire Farm-In Interest.

In the event Terra Nova elects to complete either or both of the first two wells drilled in connection with the initial three well drilling program, Terra Nova shall pay 50% of the completion costs and we will pay the other 50% of the completion costs. In the event Terra Nova elects to complete the third well drilled in connection with the initial three well drilling program, or any well drilled in connection with the optional three well drilling program, Terra Nova shall pay 50% of the completion costs, and we, ACOR and Sakhai shall pay the other 50% of the completion costs in accordance with our working interest at the effective date of the Terra Nova Farm-In Agreement.

Terra Nova will earn the Farm-In Interest in stages based upon successful completion of specific Earning Obligations. In each instance, we, ACOR and Sakhai will each contribute a portion of the working interest earned by Terra Nova. In the event Terra Nova earns the entire Farm-In Interest, we, ACOR and Sakhai will transfer to Terra Nova the following working interest percentages in both PEL 112 and PEL 444:

(a)	We will contribute an undivided 38.556% working interest in both PEL 112 and PEL 444 (resulting in a residual working interest position of 28.112% in each license);
(b)	ACOR will contribute an undivided 8.222% working interest in both PEL 112 and PEL 444; and
(c)	Sakhai will contribute an undivided 8.222% working interest in both PEL 112 and PEL 444.

During February 2013, Terra Nova delivered copies of the data acquired in connection with its acquisition of 127 square kilometers of a 3-D seismic data on PEL 112 under the terms of the Terra Nova Farm-In Agreement. Terra Nova also delivered its interpretation of that data which identified four drilling prospects on the acreage surveyed. As a result, Terra Nova has effectively completed its Earning Obligation with respect to PEL 112 seismic acquisition, and has earned an undivided 20% working interest in that license. We, ACOR and Sakhai have each contributed a portion of the working interest earned by Terra Nova as follows:

(a)	We contributed an undivided 13.3334% working interest in PEL 112 resulting in a residual working interest position of 53.333% in that license;
(b)	ACOR contributed an undivided 3.3333% working interest in PEL 112; and
(c)	Sakhai contributed an undivided 3.3333% working interest in PEL 112.

We are currently processing the documents required to facilitate the transfer of the working interest earned by Terra Nova.

The Terra Nova Farm-In Agreement may be terminated by any party upon the occurrence of an uncured breach of any material term. Terra Nova may terminate the Agreement any time before it has earned the Farm-In Interest upon providing written notice of such termination. In the event Terra Nova terminates the Agreement, it shall not be entitled to any interest in PEL 444 unless it has satisfied an Earning Obligation with respect to that license.

On February 27, 2012, we terminated a previous farm-in agreement on PEL 112 and PEL 444 with Brandenburg Energy Corp. ("Brandenburg"). Brandenburg’s contract rights were subject to meeting certain milestones including an obligation to pay us AUD$7,400,000 (USD$7,822,000) on or before September 20, 2011. Brandenburg was unable to pay this amount. On February 27, 2012, we terminated our agreement with Brandenburg.

Cooper Basin exploration activity

Our initial Cooper Basin exploration plan includes the acquisition of 3D seismic data on PEL 112 and PEL 444, and the drilling, completion and equipping of six (6) wells shared across both licenses. Current estimates indicate the costs to perform this work could range from $31 million to $33 million.

Acquisition of 127 square kilometers of 3-D seismic data on PEL 112 began July 24, 2012, and was completed in late September 2012. This seismic survey fulfilled our minimum work obligation for PEL 112 License Year Four which ended January 10, 2013. Geokinetics (Australia) Pty. Ltd. undertook the 3D seismic survey which focused on the northern most portion of PEL 112 and covered approximately 6% of its available acreage.

Seven drilling targets were identified as a result of the final interpretation of the PEL 112 seismic data. We believe our primary drilling targets are similar geologically to producing structures observed in existing oil pools (including the Butlers, Perlubie and Parsons fields) located to the north of PEL 112 on the Cooper Basin’s western-flank. Seismic interpretation indicates that all primary targets display 4-way structural closures.

During January 2013, Terra Nova committed to drill 3 wells (with an option of two additional wells), using Hunt Energy & Minerals Co. – Australia Pty. Ltd. (“Hunt”). It is anticipated that well locations will be spread between the PEL 112 and PEL 444 licenses. Hunt is a drilling contractor with over 25 years of experience in the Cooper-Eromanga Basin. Terra Nova has deposited AUD$200,000 (USD$208,500) with Hunt to initiate rig assembly.

Work Area Clearance (“WAC”) on PEL 112 access roads and drill site locations began April 20, 2013 and was completed on April 22, 2013. WAC is the process by which anthropologists and representatives of Australia’s Native Title Holders review exploration sites to insure planned activity does not harm the cultural integrity of the land to be explored. Permits for roads and well site construction are expected in mid-to-late May 2013, with road construction and site preparation scheduled for completion in late June 2013. We estimate that the first well will be drilled on PEL 112, subject to approvals and final rig availability, in mid-July 2013.

We are also working with Terra Nova to acquire 80 square kilometer 3D seismic data on PEL 444. Data acquisition is scheduled for mid-2013. We understand that acquisition of this 3D seismic data will fulfill our minimum work obligation for PEL 444 License Year Three which will end on July 11, 2013. WAC on PEL 444 began April 9, 2013 was completed on April 19, 2013.

During 2011 and 2010, we completed WAC on PEL 112 and undertook processing of more than 666 km (414 miles) of 2D seismic data. This reprocessing covered a significant portion of PEL 112 and PEL 444. Our 2D seismic reprocessing was performed by Dayboro Geophysical Pty Ltd (“Dayboro”) under the supervision of Isis Petroleum Consultants Pty Ltd (“Isis”). Both Dayboro and Isis are independent engineers with lengthy geological and geophysical work experience in the Cooper Basin. The processing sequence targeted lines which complimented our technical assessment of likely drilling prospects and future seismic acquisition.

We have also completed a broad range of technical studies relating to PEL 112 and PEL 444. In largest part, the studies were performed by Isis and included; a) a review of Cooper Basin exploration acreage (including an analysis of the chronostratigraphy, an assessment of neighboring exploration results, an analysis of petroleum systems and a probabilistic volumetric assessment of leads), b) oil migration studies, c) adjacent oil pools studies, and d) economic feasibility studies. In the opinion of management, these studies increased the value of both licenses.

Results of Operations

Our consulting, management and professional fees for the three months ended March 31, 2013, remained relatively steady when compared to the same period during the prior fiscal year. Our office and travel expenses, however, increased by $9,981 (39%) on a comparative basis during those periods as a result of an increase in current year travel to support our upcoming exploration plans. We also incurred interest of $11,237 during the three months ended March 31, 2013 relating to a loan of $1,000,000 finalized in late December 2012 (see further details below). We had no material borrowings or interest during the three months ended March 31, 2012.

The Australian dollar increased from 1.037 to 1.042 US dollars, and from 1.020 to 1.039 US dollars, during the three month periods ended March 31, 2013 and 2012, respectively. As a result, we recognized foreign exchange losses of $24,748 and $105,956 during the respective periods. Substantially all of our non-cash foreign exchange losses relate to the measurement of US dollars required to settle deferred taxes payable to the Australian Government.

On an inception to date basis, we have recognized a net loss of approximately $14,531,000. In largest part, that loss consisted of non-cash expense including: stock-based fees and compensation expense of $3,339,000, unrealized foreign exchange loss of $978,000, and a net impairment of oil and gas properties of approximately $5,152,000. In addition, we have incurred $1,671,000 related to the discontinued operations of a former subsidiary, and approximately $3,391,000 in other net losses, related to exploration stage operations.

Financial Condition, Liquidity and Capital Resources

The execution of the Terra Nova Farm-In Agreement significantly enhances our exploration capacity. On May 11, 2012, Terra Nova closed an equity financing for gross proceeds equal to CAD$10,652,000 (USD$10,663,000). During May 2012, Terra Nova placed AUD$4,700,000 (USD$4,968,000) in escrow which was used for the completion of a seismic acquisition program sufficient to meet the minimum seismic acquisition, processing and interpretation requirements. On November 1, 2012, Terra Nova deposited AUD$4,500,000 (USD$4,670,000) in escrow as a deposit to sole fund the dry-hole costs of an initial three (3) well drilling program.

Based upon technical recommendations, we have pursued the acquisition of 3-D seismic data on our licenses. The current Cooper Basin exploration plan also calls for the drilling, abandonment or completion, and possible equipping of six wells. Current estimates indicate the costs to perform the work outlined in our Cooper Basin exploration plan would range from $31 million to $33 million. Of this amount, approximately $4.3 million has already been expended. Under the terms of the Terra Nova Farm-In Agreement, we estimate that Terra Nova will bear $25.5 to $26 million, we would bear $4.0 to $5.0 million and our other working interest partners would bear $1.5 to $2 million, of planned exploration costs.

Our operations to date have been financed from the sale of our securities, loans from unrelated third parties and advances from Holloman Corporation, our current and former officers, directors and their affiliates. We regularly review the market to identify opportunities for capital formation.

During 2012, in connection with the Terra Nova Farm-In Agreement, Terra Nova paid us cash fees totaling $350,000. We determined that $54,719 of the cash fees paid by Terra Nova were refundable to ACOR and Sakhai under the terms of a cost sharing agreement with them. Of that amount, we have withheld $37,340 as a recovery of exploration costs payable to us by ACOR and Sakhai.

During fiscal 2011, we received non-refundable contract payments totaling $261,212 in connection with our farm-in agreement with Brandenburg. Of the contract payments received, $221,118 were classified as contract advances, and $47,254 were recognized as other income. Contract advances totaling $213,958 were used to offset Brandenburg transaction expenses and the costs associated with work area clearance and the acquisition of seismic data on PEL 112 and PEL 444.

On December 24, 2012 we borrowed $1,000,000 (the “Loan”) from LPD Investments Ltd. (“Lender”). The Loan bears interest at 4.5% per annum and provides for a penalty rate of interest of 10% per year on any unpaid principal which is not paid when due. The Loan is payable upon demand of the Lender at any time, and may be prepaid by us without notice or penalty. The Lender is an unrelated party. Holloman Corporation has guaranteed our obligations under the Loan. Other than this Loan, and the obligations associated with our oil and gas concessions in Australia which include a formal authorization for expenditure in the amount of $700,000 relating to our portion of upcoming seismic exploration expenditures, we had no material future contractual obligations as of March 31, 2013.

On March 1, 2012, we borrowed $100,000 from a consultant who is also a shareholder. The loan was non-interest bearing and payable upon demand. The entire amount of the loan was repaid on March 23, 2012.

During March 2011, we sold 1,400,002 shares of common stock in a private placement of investment units. Proceeds from the private placement totaled $210,000. Of that amount, $180,000 was paid in cash and $30,000 was a conversion of liabilities.

Effective October 1, 2010, we executed an administrative services agreement with our controlling shareholder. Under this agreement, fees of $5,000 per month are payable to Holloman Corporation covering; office and meeting space, supplies, utilities, office equipment, network access and other administrative facilities costs. These fees are payable quarterly in shares of our restricted common stock at the closing price of the stock on the last trading-day of the applicable monthly billing period. This administrative services agreement can be terminated by either party with 30-days notice. During the three month period ended March 31, 2013, we paid administrative fees totaling $15,000 using 36,033 shares of our common stock, at approximate weighted average price of $0.416 per share. Proceeds from this administrative service agreement have been assigned to a wholly owned subsidiary of Holloman Corporation.

The oil and gas industry is cyclical in nature and tends to reflect general economic conditions. The US and other world economies are recovering from a recession which continues to inhibit investment liquidity. Though oil prices are trending higher, the pattern of historic price fluctuations has resulted in additional uncertainty in capital markets. Our access to capital, as well as that of our partners and contractors, may be limited due to tightened credit markets. In addition, the results of our operations will be significantly impacted by a variety of trends and factors including; (i) our exploration success and the marketability of future production, if any, (ii) increasing competition from larger companies, (iii) future fluctuations in the prices of oil and gas, and (iv) our ability to maintain or increase oil and gas production through exploration and development activities.

We believe our plan of operations may require up to $13 million for exploration costs and administrative expenses over the twelve-month period ending April 30, 2014. We anticipate that our working interest partners will bear up to $10 million and that we may bear up to $3 million of that amount. We are attempting to raise investment capital to cover our portion of anticipated costs.

If we are unable to raise the financing we need, our business plan may fail and our stockholders could lose their investment. If we are unable to perform in accordance with the work programs required by our licenses, the Australian government could cancel our exploration rights. There can be no assurance that we will be successful in raising the capital we require, or that if capital is offered, it will be subject to terms we consider acceptable. Investors should be aware that even in the event we are able to raise the funds we require, there can be no assurance that we will succeed in our drilling or production plans and we may never be profitable.

As of May 14, 2013 we did not have any off balance sheet arrangements.

As of May 14, 2013 we did not have any proven oil or gas reserves and we did not have any revenues.

Critical Accounting Policies and Estimates

Measurement Uncertainty

The process of preparing financial statements requires that we make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts. Our estimates and assumptions are based on current facts, historical experience and various other factors we believe to be reasonable under the circumstances. The most significant estimates with regard to the unaudited consolidated financial statements included with this report relate to carrying values of oil and gas properties, determination of fair values of stock based transactions, and deferred income tax rates and timing of the reversal of income tax differences.

These estimates and assumptions are reviewed periodically and, as adjustments become necessary, they are reported in earnings in the periods in which they become known.

Petroleum and Natural Gas Properties

We utilize the full cost method to account for our investment in oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including such costs as leasehold acquisition costs, interest costs relating to unproved properties, geological expenditures, tangible and intangible development costs, including direct internal costs, are capitalized to the full cost pool. When we commence production from established proven oil and gas reserves, capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage, will be depleted on the units-of-production method using estimates of proved reserves. Costs of unproved properties are not amortized until the proved reserves associated with the projects can be determined or until impairment occurs. If an assessment of such properties indicates that properties are impaired, the amount of impairment is added to the capitalized cost base to be amortized.

The capitalized costs included in the full cost pool are subject to a "ceiling test", (based on the average of 12 month, first-day-of-the-month pricing), which limits such costs to the aggregate of the (i) estimated present value, using a ten percent discount rate, of the future net revenues from proved reserves, based on current economic and operating conditions, (ii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, (iii) the cost of properties not being amortized, less (iv) income tax effects related to differences between the book and tax basis of the cost of properties not being amortized and the cost or estimated fair value of unproved properties included in the costs being amortized. At March 31, 2013, all of our oil and gas interests were classified as unproven properties and were not being amortized.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the statement of operations.

Fair Value Measurements

Our valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

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Level 1 — quoted prices in active markets for identical assets or liabilities.

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Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

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Level 3 — unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

We consider all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. Cash and cash equivalents totaled $878,354 and $1,009,882 at March 31, 2013 and December 31, 2012, respectively. We are exposed to a concentration of credit risk with respect to our cash deposits. We place cash deposits with highly rated financial institutions in the United States and Australia. At times, cash balances held in financial institutions may be in excess of insured limits. We believe the financial institutions are financially strong and the risk of loss is minimal. We have not experienced any losses with respect to the related risks and do not believe our exposure to such risks is more than normal.

The estimated fair values for financial instruments are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, other receivables, accounts payable, accrued liabilities and demand notes payable approximates their carrying value due to their short-term nature.

Stock Based Compensation

We record compensation expense for stock based payments using the fair value method. The fair value of stock options granted to directors and employees is determined using the Black-Scholes option valuation model at the time of grant. Fair value for common shares issued for goods or services rendered by non-employees is measured based on the fair value of the goods and services received. Share-based compensation is expensed with a corresponding increase to share capital. Upon the exercise of the stock options, the consideration paid is recorded as an increase in share capital.

Foreign Currency Translation

Our functional and reporting currency, and that of our Australian subsidiary, is the United States dollar. The financial statements of our Canadian subsidiary (which is relatively inactive) are translated to United States dollars using period-end rates of exchange for assets and liabilities, and average rates of exchange for the period for revenues and expenses. Translation gains (losses) are recorded in accumulated other comprehensive income as a component of stockholders’ equity. Foreign currency financial statements of our Australian subsidiary use period end rates for monetary assets and liabilities, historical rates for historical cost balances, and average rates for expenses. If material, translation gains and losses are included in the determination of income. Foreign currency transactions are primarily undertaken in Canadian and Australian dollars. As of March 31, 2013, we have not entered into derivative instruments to offset the impact of foreign currency fluctuations.

Other Comprehensive Income (Loss)

We report and display comprehensive loss and its components in our consolidated financial statements. For the three month periods ended March 31, 2013 and 2012, the only components of comprehensive loss were foreign currency translation adjustments.

Income Taxes

We follow the asset and liability method of accounting for future income taxes. Under this method, future income tax assets and liabilities are recorded based on temporary differences between the carrying amount of balance sheet items and their corresponding tax bases. In addition, the future benefits of income tax assets, including unused tax losses, are recognized, subject to a valuation allowance, to the extent that it is more likely than not that such future benefits will ultimately be realized. Future income tax assets and liabilities are measured using enacted tax rates and laws expected to apply when the tax liabilities or assets are to be either settled or realized.

Earnings per share

We present both basic and diluted earnings (loss) per share (EPS) on the face of the consolidated statements of operations. Basic EPS is computed by dividing net earnings (loss) available to common shareholders by the weighted average number of shares outstanding during the period. Diluted EPS gives effect to all potential dilutive common shares outstanding during the period including convertible debt, stock options, and warrants, using the treasury stock method. Diluted EPS excludes all potential dilutive shares if their effect is anti-dilutive. Diluted EPS figures are equal to those of basic EPS for each period since we have generated losses during the periods covered by this report, and have no dilutive stock options or warrants.

See Note 1 to our unaudited consolidated financial statements for a discussion of recent accounting pronouncements.

ITEM 4.

CONTROLS AND PROCEDURES.

An evaluation was carried out under the supervision and with the participation of our management, including our Principal Financial Officer and Principal Executive Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-Q. Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-Q, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive Officer and Principal Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our management concluded that, as of March 31, 2013, our disclosure controls and procedures were effective.

Change in Internal Control over Financial Reporting

Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles in the United States. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives.

There were no changes in our internal control over financial reporting that occurred during the fiscal quarter covered by this report that materially affected or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 2.

UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS.

On March 31, 2013, we issued 36,033 shares of our common stock, at an average price of $0.416 per share, in connection with the conversion of $15,000 in administrative service fees payable to a wholly owned subsidiary of our controlling shareholder, Holloman Corporation. The certificates representing the shares will bear a restricted legend providing that they cannot be sold unless pursuant to an effective registration statement or an exemption from registration. We relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 in connection with the issuance of these shares and did not pay any underwriting discounts or sales commissions.

ITEM 6.

EXHIBITS

Exhibit Number		Description of Exhibit

3.1		Articles of Incorporation(1)
3.2		Corporate Bylaws(1)
10.1		Share Exchange Agreement between Endeavor Energy Corporation, First Endeavor Holdings Inc. and Endeavor Canada Corporation(2)
10.2		Agreement between Endeavor Energy Corporation and Holloman Petroleum Pty. Ltd. for the purchase of assets and exchange of shares(3)
10.3		Option Agreement between Holloman Energy Corporation and Cameron King for an exchange of shares of Endeavor Canada Corporation(4)
10.4		Notice of Option Exercise relating to the Option Agreement between Holloman Energy Corporation and Cameron King for an exchange of shares of Endeavor Canada Corporation(4)
10.5		Farm Out Commitment Agreement between Holloman Energy Corporation and Holloman Oil & Gas, Ltd.(4)
10.6		Brandenburg Oil & Gas Farm-In Agreement, Petroleum Exploration Licenses 112 and 444 dated July 29, 2011(6)
10.7		Terra Nova Oil & Gas Farm-In Agreement, PELs 112 and 444, and Letter Agreement – Transaction Cost Sharing (7)
14.1		Code of Ethics for Principal Executive and Senior Financial Officers(5)
21.1		As of March 31, 2013 our subsidiaries were:
		First Endeavor Holdings Inc. (100% Owned) Alberta corporation
		Holloman Petroleum Pty. Ltd. (100% Owned) Australian corporation
		Endeavor Exploration Pty. Ltd. (100% Owned) Australian corporation
		All subsidiaries conduct business under their own names
31.1		Rule 13a-14(a) Certifications
31.2		Rule 13a-14(a) Certifications
32		Section 1350 Certifications

101. INS		XBRL Instance Document
101. SCH		XBRL Schema Document
101. CAL		XBRL Calculation Linkbase Document
101. DEF		XBRL Taxonomy Extension Definition Linkbase Document
101. LAB		XBRL Label Linkbase Document
101. PRE		XBRL Presentation Linkbase Document

———————

(1)	Previously filed with our Form SB-2 on January 23, 2006 and incorporated by reference.
(2)	Previously filed with our Form 8-K on August 9, 2007 and incorporated by reference.

(3)	Previously filed with our Form 8-K on November 29, 2007 and incorporated by reference.
(4)	Previously filed with our Form 10-KSB on April 15, 2008 and incorporated by reference.

(5)	Previously filed with our Form 10-KSB/A on April 26, 2007 and incorporated by reference.
(6)	Previously filed with our Form 8-K on August 4, 2011 and incorporated by reference.
(7)	Previously filed with our Form 10-Q on May 15, 2012 and incorporated by reference.

SIGNATURES

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

	HOLLOMAN ENERGY CORPORATION

Date: May 14, 2013	By:	/s/ Mark Stevenson
		Mark Stevenson, Principal Executive Officer

Date: May 14, 2013	By:	/s/ Robert Wesolek
		Robert Wesolek, Principal Financial and Accounting Officer

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