Stratex Oil & Gas Holdings, Inc. - FORM 8-K/A

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________

FORM 8-K/A

(Amendment No. 3)

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of Earliest Event Reported): July 6, 2012

STRATEX OIL & GAS HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

Colorado		333-164856	94-3364776
(State or other jurisdiction of incorporation)		(Commission File Number)	(I.R.S. Employer Identification No.)

30 Echo Lake Road, Watertown, CT			06795
(Address of principal executive offices)			(Zip Code)

	860-604-1472
	(Registrant’s telephone number, including area code)

Poway Muffler and Brake, Inc., 13933 Poway Rd., Poway, CA 92064
(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

EXPLANATORY NOTE

This Amendment No. 2 to Current Report on Form 8-K/A (“Amendment No. 2”) amends the Current Report on Form 8-K filed with the Securities and Exchange Commission (“SEC”) by Stratex Oil & Gas Holdings, Inc. (the “Company”) on July 12, 2012 (the “8-K”) in connection with the Transactions (defined herein). This Amendment No. 2 is being filed to incorporate the Company’s revisions and responses pursuant to certain comment letters to the 8-K received from the SEC dated August 10, 2012 and August 24, 2012 respectively. Additionally, Amendment No.2 does not reflect any event occurring after July 6, 2012.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This current report contains forward-looking statements within the meaning of applicable securities laws. These statements relate to anticipated future events, future results of operations or future financial performance. These forward-looking statements include, but are not limited to, statements relating to our ability to raise sufficient capital to finance our planned operations, market acceptance of our technology and product offerings, our ability to attract and retain key personnel, our ability to protect our intellectual property, and estimates of our cash expenditures for the next 12 to 36 months. In some cases, you can identify forward-looking statements by terminology such as “may,” “might,” “should,” “intends,” “expects,” “plans,” “goals,” “projects,” “anticipates,” “believes,” “estimates,” “predicts,” “potential,” or “continue” or the negative of these terms or other comparable terminology.

These forward-looking statements are only predictions, are uncertain and involve substantial known and unknown risks, uncertainties and other factors which may cause our (or our industry’s) actual results, levels of activity or performance to be materially different from any future results, levels of activity or performance expressed or implied by these forward-looking statements. The “Risk Factors” section of this current report sets forth detailed risks, uncertainties and cautionary statements regarding our business and these forward-looking statements.

We cannot guarantee future results, levels of activity or performance. You should not place undue reliance on these forward-looking statements, which speak only as of the date that they were made. These cautionary statements should be considered with any written or oral forward-looking statements that we may issue in the future. Except as required by applicable law, including the securities laws of the United States, we do not intend to update any of the forward-looking statements to conform these statements to reflect actual results, later events or circumstances or to reflect the occurrence of unanticipated events.

EXPLANATORY NOTE

Ross Investments, Inc. (“Ross Investments”) was incorporated in January 1989 under the laws of the State of Colorado. Until December 2008, Ross Investments’ operations were focused on the development of software for online trading of rare coins.

On December 15, 2008, Ross Investments completed a merger with Poway Muffler and Brake, Inc., a California corporation (“PMB-CA”). PMB-CA was established in 1994 as a retail automotive repair and maintenance service business. Pursuant to the Share Exchange Agreement, each of the outstanding shares of PMB-CA common stock was converted into one share of Ross Investments common stock. In addition, upon the closing of the transaction, Ross Investments amended its Articles of Incorporation to change its name from Ross Investments, Inc. to Poway Muffler and Brake, Inc.

On May 25, 2012, Poway Muffler and Brake, Inc. filed an Amendment to the Certificate of Incorporation by which Poway Muffler and Brake, Inc., a Colorado corporation, changed its name to Stratex Oil and Gas Holdings, Inc. (“Pubco”), with the Secretary of the State of Colorado.

On July 6, 2012, Stratex Acquisition Corp. (“Acquisition Corp.”), a wholly-owned subsidiary of Pubco, merged (the “Merger”) with and into Stratex Oil & Gas, Inc., a Delaware corporation (“Stratex”). Stratex was the surviving corporation of that Merger. As a result of the Merger, Pubco acquired the business of Stratex, and will continue the existing business operations of Stratex as a wholly-owned subsidiary.

As used in this Current Report, the terms the “Company”, “we,” “us,” and “our” refer to Pubco and its wholly-owned subsidiary Stratex, after giving effect to the Merger, unless otherwise stated or the context clearly indicates otherwise. The term “Pubco” refers to Pubco before giving effect to the Merger; and the term “Stratex” refers to Stratex Oil & Gas, Inc., before giving effect to the Merger.

This Current Report contains summaries of the material terms of various agreements executed in connection with the transactions described herein. The summaries of these agreements are subject to, and are qualified in their entirety by, reference to these agreements, all of which are incorporated herein by reference.

This current report is being filed in connection with a series of transactions consummated by the Company and certain related events and actions taken by the Company.

This current report responds to the following items on Form 8-K:

Item 1.01

Entry into a Material Definitive Agreement

Item 2.01

Completion of Acquisition or Disposition of Assets

Item 3.02	Unregistered Sales of Equity Securities

Item 4.01	Changes in Registrant’s Certifying Accountant

Item 5.01

Changes in Control of Registrant

Item 5.02

Departure of Directors or Principal Officers; Election of Directors; Appointment of Principal Officers; Compensatory Arrangements of Certain Officers

Item 5.06

Changes in Shell Company Status

Item 9.01	Financial Statements and Exhibits

Table of Contents

Item 1.01.	Entry into a Material Definitive Agreement	5
Item 2.01.	Completion of Acquisition or Disposition of Assets	5
	THE MERGER AND RELATED TRANSACTIONS	5
	DESCRIPTION OF BUSINESS	8
	DESCRIPTION OF PROPERTY	12
	RISK FACTORS AND SPECIAL CONSIDERATIONS	32
	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	62
	SECURITY OWNERSHIP OF CERTAIN STOCKHOLDERS AND MANAGEMENT	71
	DIRECTORS AND EXECUTIVE OFFICERS	72
	EXECUTIVE COMPENSATION	75
	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	79
	DESCRIPTION OF CAPITAL STOCK	79
	MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS	81
	LEGAL PROCEEDINGS	81
	RECENT SALES OF UNREGISTERED SECURITIES	82
	INDEMNIFICATION OF OFFICERS AND DIRECTORS	83
	PART F/S	84
	INDEX TO EXHIBITS	84
	DESCRIPTION OF EXHIBITS	84
Item 3.02.	Unregistered Sales of Equity Securities.	84
Item 4.01.	Changes in Registrant’s Certifying Accountant.	84
Item 5.01.	Changes in Control of the Registrant.	85
Item 5.02.	Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.	85
Item 5.06.	Changes in Shell Company Status	86
Item 9.01.	Financial Statements and Exhibits.	86

Item 1.01. Entry into a Material Definitive Agreement

On July 6, 2012, we entered into an Agreement and Plan of Merger and Reorganization, which we refer to in this Current Report as the “Merger Agreement”, and completed the Merger. For a description of the Merger and the material agreements entered into in connection with the Merger, please see the disclosures set forth in Item 2.01 to this Current Report, which disclosures are incorporated into this item by reference.

Item 2.01. Completion of Acquisition or Disposition of Assets

THE MERGER AND RELATED TRANSACTIONS

The Merger

On July 6, 2012 (which we refer to as the “Closing Date”), Pubco, Stratex and Acquisition Corp. entered into the Merger Agreement and completed the Merger. Before their entry into the Merger Agreement, no material relationship existed between Pubco (or its Acquisition Corp. subsidiary) and Stratex. A copy of the Merger Agreement is attached as Exhibit 2.1 to this Current Report and is incorporated herein by reference.

Pursuant to the Merger Agreement, on the Closing Date, Acquisition Corp., a wholly-owned subsidiary of Pubco merged with and into Stratex, with Stratex remaining as the surviving entity. Pubco acquired the business of Stratex pursuant to the Merger and will continue the existing business operations of Stratex as a wholly-owned subsidiary.

Simultaneously with the Merger, on the Closing Date all of the issued and outstanding shares of Stratex common stock converted, on a 2 for 1 basis, into shares of the Company’s common stock, no par value per share (“Common Stock”). Also on the Closing Date, all of the issued and outstanding options to purchase shares of Stratex common stock, and all of the issued and outstanding warrants (collectively the “Stratex Convertible Securities”) to purchase shares of Stratex Common Stock, upon the exercise or conversion of the Stratex Convertible Securities, shall have the right to convert such Stratex Convertible Securities into the kind and amount of the Company’s shares of Common Stock and other securities and property which such holder would have owned or have been entitled to receive of Stratex prior to the Closing of the Merger, on a 2 for 1 basis. The options will be administered under Stratex’s 2012 Equity Incentive Plan (the “Stratex Plan”), which the Company assumed and adopted on the Closing Date in connection with the Merger.

On the Closing Date, (i) approximately 33,372,550 shares of Common Stock were issued to former Stratex stockholders; 100 shares of Series A Preferred Stock were issued to former holders of Stratex Series A Preferred Stock (iii) options to purchase 3,000,000 shares of Common Stock granted under the Stratex Plan pursuant to the assumption of the Stratex Plan; (iv) Warrants to purchase 675,000 shares of Common Stock at $0.70 per share issued to holders of 1,350,000 Stratex Warrants (that were exercisable at a price of $.35 per share) were assumed by the Company. In addition, pre-Merger stockholders of Pubco retained 6,110,000 shares of Common Stock.

The Merger Agreement contains customary representations, warranties and covenants of Pubco, Stratex, and, as applicable, Acquisition Corp., for like transactions. Breaches of representations and warranties are secured by customary indemnification provisions.

The Merger will be treated as a recapitalization of the Company for financial accounting purposes. The historical financial statements of Pubco before the Merger will be replaced with the historical financial statements of Stratex before the Merger in all future filings with the Securities and Exchange Commission (the “SEC”).

Following the Closing Date, our board of directors consists of two members. In keeping with the foregoing, on the Closing Date, Alan Ligi, the sole director of Pubco before the Merger, appointed Stephen Funk and Timothy Kelly to fill vacancies on the board of directors, and Alan Ligi resigned his position as a director. Also on the Closing Date, Alan Ligi, the sole officer of Pubco, resigned and new executive officers designated by Stratex were appointed. Our officers and directors as of the Closing Date are identified in this Current Report under the heading “Directors and Executive Officers.”

Before the Merger, Pubco’s board of directors adopted and assumed the Stratex Plan. The Stratex Plan provides for the issuance of 12,000,000 shares of our Common Stock to executive officers, directors, advisory board members and employees. The parties have taken all actions necessary to ensure that the Merger is treated as a tax free exchange under Section 368(a) of the Internal Revenue Code of 1986, as amended.

Recapitalizations, etc.

Stratex Reincorporation

Stratex was originally organized as a Connecticut corporation on January 25, 2011. Effective February 18, 2011, Stratex converted to a Delaware corporation. Stratex was originally authorized to issue 40,000 shares of common stock, $0.0001 par value per share. By Certificates of Amendment dated April 1, 2011 and March 30, 2012, the authorized shares of common stock were increased to 85,000,000 shares and 125,000,000 shares, respectively. In addition, the April 1, 2011 Certificate of Amendment authorized Stratex to issue up to 100 shares of preferred stock, $0.0001 par value per share. Prior to the Closing Date 100 shares of preferred stock, designated as Series A Preferred Stock, were issued and outstanding.

Pubco Recapitalization

In addition to the transactions described under the heading “Explanatory Note,” on May 25, 2012, Pubco undertook a 3.5 for 1 forward stock split. Also, prior to the Merger the Pubco board of directors incorporated its wholly owned subsidiary PMB Holdings, Inc., a company organized under the laws of Nevada (“PSOS”). Pubco split-off (the “Split-Off”) ownership of PSOS to its sole executive officer and director (the “Split-Off Shareholder”).

Split-Off Agreement

On the Closing Date, Pubco split off its wholly-owned subsidiary PSOS. The Split-Off was accomplished through the cancellation of a portion of an outstanding loan owed to the Split-Off Shareholder by Pubco in the amount of $79,687 as consideration for Pubco’s assets and liabilities. The assets and liabilities of Pubco were transferred to the Split-Off Shareholder in the Split-Off. Pubco executed a split off agreement with the Split-Off Shareholder, a copy of which is attached as Exhibit 10.1 to this Current Report and is incorporated herein by reference.

The Merger, the Split-Off and the related transactions are collectively referred to in this Current Report as the “Transactions.”

Current Ownership

Immediately after giving effect to the Transactions, options granted under the Stratex Plan (which we assumed), and the assumption of warrants, our issued and outstanding securities on the closing of the Transactions is as follows:

§	Approximately 39,482,550 shares of Common Stock;

§	100 shares of series A preferred stock;

§	Options to purchase 3,000,000 shares of Common Stock granted under the Stratex Plan;

§	Warrants to purchase 675,000 shares of Common Stock at a price of $0.70 per share held by Stratex warrant holders.

Accounting Treatment; Change of Control

The Merger is being accounted for as a “reverse merger,” and Stratex is deemed to be the acquirer in the reverse merger. Consequently, the assets and liabilities and the historical operations that will be reflected in the financial statements prior to the Merger will be those of Stratex, and the consolidated financial statements after completion of the Merger will include the assets and liabilities of Stratex, historical operations of Stratex and operations of Stratex from the Closing Date of the Merger. Except as described in the previous paragraphs, no arrangements or understandings exist among present or former controlling stockholders with respect to the election of members of our board of directors and, to our knowledge, no other arrangements exist that might result in a change of control of the Company. Further, as a result of the issuance of the shares of Common Stock pursuant to the Merger, a change in control of the Company occurred as of the date of consummation of the Merger.

DESCRIPTION OF BUSINESS

Immediately following the Merger, the business of Stratex became our business.

Certain Definitions

The following oil and gas measurements and industry and other terms are used in this Current Report on Form 8-K.

Bakken Shale—means the Bakken Shale oil play in the Williston Basin and can include the Three Forks Sanish, Heath and Tyler formations.

Barrel—means one barrel of petroleum products that equals 42 U.S. gallons.

BBtu—means one billion BTUs.

BBtu/d—means one billion BTUs per day.

Bcfe—means one billion cubic feet of gas equivalent determined using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

Bcf/d—means one billion cubic feet per day.

BLM—means the Bureau of Land Management.

Boe—means barrels of oil equivalent.

Boe/d—means barrels of oil equivalent per day.

British Thermal Unit or BTU—means a unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit.

FERC—means the Federal Energy Regulatory Commission.

Fractionation—means the process by which a mixed stream of natural gas liquids is separated into its constituent products, such as ethane, propane and butane.

HBP Acreage—means Held by production acreage

LOE—means lease and other operating expense excluding production taxes, ad valorem taxes and gathering, processing and transportation fees.

Mbbls—means one thousand barrels.

Mbbls/d—means one thousand barrels per day.

Mboe/d—means one thousand barrels of oil equivalent per day.

Mcf—means one thousand cubic feet.

Mcfe—means one thousand cubic feet of gas equivalent using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

MMbbls—means one million barrels.

MMboe—means one million barrels of oil equivalent.

MMBtu—means one million BTUs.

MMBtu/d—means one million BTUs per day.

MMcf—means one million cubic feet.

MMcf/d—means one million cubic feet per day.

MMcfe—means one million cubic feet of gas equivalent using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

MMcfe/d—means one million cubic feet of gas equivalent per day using the ratio of one barrel of oil, condensate or NGLs to six thousand cubic feet of natural gas.

NGLs—means natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels and gasoline additives, among other applications.

PV10—means the present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual discount rate of 10%.

We are an independent energy company focused on the exploration, acquisition and production of crude oil in North Dakota, Montana, Colorado, Kansas, and Nebraska. Our oil and natural gas operations are primarily concentrated in the Williston Basin of North Dakota and Montana and the Denver-Julesburg Basin in Colorado. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects, and evaluate those prospects using subsurface geology, geophysical data and exploratory drilling. Using this strategy, we intend to develop an oil portfolio of proven reserves, as well as developmental and exploratory drilling opportunities.

Our core operating areas are in the Williston Basin in North Dakota and Montana and the Denver-Julesburg Basin in Colorado. In the Williston Basin, we focus on oil production from multiple zones including the Bakken Shale, and Three Forks Sanish Formations. In the Denver-Julesberg Basin we focus on the Niobrara Formations.

We use geologists, petroleum engineers and geophysicists that have years of relevant industry experience in the basins where we operate.

Business Model

We explore and produce oil and gas through a non-operated business model. We participate in wells proportionately to the leasehold interest in each drilling unit that is drilled by its operating partners. As a non-operating participant we seek to minimize operating and overhead costs, however, we are liable for our share of the operating and capital costs incurred for each property by its operator. This low-cost model allows us to diversify through different operators and regions. We operate 1 oil well known as Tininenko 4-19 in Roosevelt County MT. As its discretion management may decide to acquire additional operated assets.

Operations

Our management team has structured our operations in a manner that minimizes operating and overhead costs as a leasehold interest owner. As a non-operating participant, we intend to rely on operating partners to conduct the drilling process and to bear operating and overhead costs, which should allow us to invest the highest possible working interest while minimizing costs.

Drilling and Acreage Plans

Our primary focus is acquiring leasehold interests in the Bakken Formation, Three Forks-Sanish Formation, and Niobrara Formation.

The Bakken Formation

The Bakken Formation is an oil-bearing strata underlying parts of the Williston Basin of Montana and North Dakota. The Bakken is located between 8,000 and 11,000 feet below surface and is comprised of three members: the lower shale, middle dolomite, and upper shale. The middle member holds the majority to the oil reserves. Oil production in this region dates back to the 1950’s, but was largely unsuccessful. The vertical wells drilled around this time couldn’t produce oil at high rates. The vertical wells only had about 50 to 100 feet of the shaft that reached the middle Bakken. The application of horizontal wells with fracturing technology has allowed production to dramatically increase.

Niobrara Formation

The Niobrara Formation is a shale rock underlying parts of Colorado and Wyoming. Oil and natural gas can be found at depths from 3,000 to 14,000 feet. The Niobrara is a new oil formation that is part of the Denver-Julesburg basin. Oil exploitation activities in the Niobrara formation have recently begun the performance of the Niobrara and Bakken are being compared as part of the operators’ evaluation procedures.

The Three Forks-Sanish Formation

The Three Forks-Sanish Formation is an oil area below the Bakken Shale zone.

Drilling

Hydraulic Fracturing

Hydraulic Fracturing is a technique that can increase the flow of oil or gas from a well. The procedure is done by pumping high quantities of liquid down a well into the reservoir rock at a high pressure to fracture the rock. The technique creates a network of interconnected fractures that allow more oil to flow through the rock.

Horizontal Drilling

Horizontal Drilling is useful in reaching targets and stimulating reservoirs in ways that cannot be achieved with vertical wells. A rock unit that is only 50 feet thick is limited to a pay zone that is 50 feet in length with a vertical well. A well drilled horizontally can expand the limited pay zone thousands of feet. Also, horizontal drills can deliberately intersect fractures. The productivity of these wells can be increased tremendously with the use of horizontal drills.

Recent Oil Activity

DESCRIPTION OF PROPERTY

Office Locations

Our corporate offices are located at 30 Echo Lake Road, Watertown, CT, 06795. Additionally, we have a field office located at 2906 First Ave. North, Billings, MT, 59104; which is leased on a month by month basis.

Leasehold Holdings

The following represent Stratex’s mineral lease holdings as of July 6, 2012

22,000 gross and 13,900 net mineral acres in Golden Valley, North Dakota. We have leaseholds totaling 22,000 gross acres in Golden Valley, North Dakota which were acquired under a long-term lease option. The conventional oil play consists of two objective formations; 1) Bakken – a sandstone that has produced over 80M barrels of oil and is present over our acreage, 2) Three Forks Sanish.

7,274 gross and 1,661 net mineral acres located in Sheridan County, Montana.

2,080 gross and 114 net mineral acres located in Acres located in Lane and Ellis Counties, Kansas with 7 operating wells. The lease currently has 4 producing wells with an average royalty interest of .00535%, 2 producing wells with an average working interest of 7.727%. 1 well with a working interest of 8.71% is in the process of being drilled. There is also additional spacing for 18 wells.

60,000 gross and 6,000 net mineral acres located in Sioux Nebraska. This lease has the potential for over 800 horizontal wells. With a 10% interest in the field this could yield 80 net wells for Stratex.

355 gross and 120 net mineral acres located in Wattenberg Field in the Denver-Julesberg Niobrara Formation, Colorado.

640 gross and 260 net mineral acres operating well in Roosevelt County, Montana with one operating well. The Operating well (Tininencko 4-19) is producing 35 barrels per day with one Bakken drilling unit of 320 acres.

640 gross and 121 net mineral acres in Stark County, North Dakota. Stark County has seen significant development recently as firms are exploring the potential of the Bakken play in the county.

640 gross and 120 net mineral acres in Mountrail County, North Dakota. We have gained a foothold in Mountrail County, which has been the focal point of drilling in the Williston Basin and the best performing county in North Dakota. The North Dakota State Industrial Commission has reported Mountrail’s most recent monthly production rate, December 2011, at 5.1 million barrels of oil.

640 gross and 32 net mineral acres in Williams County, North Dakota. Williams County has also been a top producing county in North Dakota and the most recent production statistics by the North Dakota Industrial Commission (NDIC) report monthly production at 2.4 million barrels of oil.

640 gross and 4 net mineral acres in Divide County, North Dakota. We have acquired small leasehold in Divide County, which has picked up in development lately.

709 gross and 5 net mineral acres in Williams County, North Dakota. Williams County has also been a top producing county in North Dakota and the most recent production statistics by the NDIC report monthly production at 2.4 million barrels of oil.

Marketing and Customers

As a non-operator, we intend to rely on outside operators for the transportation, marketing/sales and account reporting for all production. The operators of our wells will be responsible for the marketing and sales of all production to regional purchasers of petroleum products, and we intend to evaluate the credit worthiness of those purchasers periodically.

Disclosure of Reserves

Below is a summary of oil and gas reserves as of the fiscal-year ended December 31, 2011 based on average fiscal-year prices.

	Reserves
Reserves category	Oil (Barrels)		Natural gas (mmcf)		Synthetic oil (mbbls)		Synthetic gas (mmcf)

Proved		12,800		0		0		0
Developed:
North America		12,800		0		0		0

Undeveloped:
North America		0		0		0		0

TOTAL PROVED				0		0		0

Our proved oil and natural gas reserves are all located in the United States, primarily in the Bakken and the Williston Basin in Montana. The reservoir engineering reports used in this prospectus are calculated as of 12/31/11. The estimates of proved reserves at 12/31/11 are based on reports prepared by LaRoache Petroleum Consultants, Ltd. (the “Engineering Reports”) which are included herein as Exhibit 99.1. Proved reserves were estimated in accordance with the guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”).

Proved reserves and future net revenue to the evaluated interests were based on economic parameters and operating conditions considered applicable as of December 31, 2011 and are pursuant to the financial reporting standards of the SEC and prepared in accordance with the SPE 2007 Standards promulgated by the Society of Petroleum Engineers. The reserves projections in this evaluation are based on the use of the available data and accepted industry-engineering methods.

Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process

Our policies regarding internal controls over the recording of reserves estimates requires reserves to comply with the SEC definitions and guidance and be prepared in accordance the SPE 2007 Standards promulgated by the Society of Petroleum Engineers. Our procedures require that our reserve report be prepared by a third-party registered independent engineering firm at the end of every year based on information we provide to such engineer. We accumulate historical production data for our wells, calculate historical lease operating expenses and differentials, update working interests and net revenue interests, obtain updated authorizations for expenditure (“AFEs”) and obtain geological and geophysical information from operators. This data is forwarded to our third-party engineering firm for review and calculation. Our Chief Executive Officer and Chief Financial Officer provide a final review of our reserve report and the assumptions relied upon in such report.

William M. Kazmann Petroleum Engineer and Geological Advisor, was our third party reserve engineer for the preparation of our reserve report, effective as of the date of purchase of the Tininenko property and December 31, 2011. Mr. Kazmann has been a petroleum engineering and geological advisor for more than 33 years with multi-disciplinary experience in the oil and gas industry. He meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Accordingly, we hired LaRoache Petroleum Ltd. as our new third-party engineering firm to prepare our reserve estimates as of the purchase date of our Tininenko property and December 31, 2011 going forward.

Proved Undeveloped Reserves

As of December 31, 2011, there were no proved undeveloped reserves. We had no operations prior to the year ended December 31, 2010.

During fiscal year 2011, we focused primarily on the acquisition of leasehold properties. As a result, investment in converting proved undeveloped reserves to proved developed reserves was limited.

Oil and Gas Production, Production Prices and Production Costs

Oil and Gas Production

The following table summarizes the production of oil and natural gas by geographical are for the fiscal year ended December 31, 2011.

Product	Williston Basin		Total
Oil (Bbls)		2,772		2,772
Gas (Mcf)		0		0
BOE		0		0

The following table summarizes gross and net productive oil wells by state as of December 31, 2011.

Production Prices

The following table summarizes the average sales price per unit of oil and natural gas by geographical area for the fiscal year ended December 31, 2011:

Product	Williston Basin		Total
Oil (Bbls)	$	84.43		$	84.43
Gas (Mcf)		0			0
Product (Mcf)		0			0
BOE	$	0		$	0

(a)

We used the 12 month first day of the month unweighted average prices realized as a basis for all oil calculations and Henry Hub for gas.

The following table summarizes the weighted average prices utilized in the reserve estimates for 12/31/11 as adjusted for location, grade and quality:

Prices utilized in the reserve estimates:
Montana oil and natural gas properties
Oil per Bbl(a)	$	86.47
Gas per MCF(a)	$	0

(a)

The pricing used to estimate our 12/31/11 reserves were based on a 12-month unweighted average realized price as adjusted for location, grade and quality.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.

Costs Incurred for Oil and Natural Gas Producing Activities

	Years Ended December 31,
	2011		2010

Unproved property acquisition costs	$	2,193,681	$	0
Exploration		0		0
Development		0		0

Total	$	2,193,681	$	0

Average production costs per BOE including ad valorem and severance taxes were $46.37 in 2011. Excluding severance taxes, production costs per BOE were $37.82.

Dry Holes

Through the date of this current report, we experienced zero dry holes.

Drilling Activity and other Exploratory and Development Activities

Productive and Exploratory Wells Drilled

In the fiscal year ended December 31, 2011, operators drilled and completed no gross and net exploratory wells on our leaseholds.

Productive and Dry Development Wells Drilled

In the fiscal year ended 12/31/11, we participated on a non-operated basis in no gross and net development wells on minority working interest acreage. We have only just begun to receive notification of development well in-fill drilling on some of our minority working interest acreage in the Bakken in early 2012.

Present Activities

We currently have 1 well that is in the process of being drilled in Lane County, Kansas which we have an 8.71% working interest in.

Delivery Commitments

We do not currently have any delivery commitments for product obtained from our wells.

Oil and Gas Properties, Wells, Operations and Acreage

The following table summarizes as of July 6, 2012, the total gross and net productive wells, expressed separately for oil and gas and the total gross and net developed acreage (i.e., acreage assignable to productive wells)

	Oil Wells				Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Williston, MT		1		260		0		0		1		260
Lane County, KS		7		114		0		0		7		114

Total

	HBP Acreage				Total Acreage
	Gross		Net		Gross		Net
Williston, MT		640		260		640		260

Lane County Kansas		2,080		114		2,080		114
Total

The following table summarizes as of July 6, 2012, the amount of undeveloped leasehold acreage expressed in both gross and net acres by geographic area and the minimum remaining terms of leases and concessions.

	HBP Acreage				Total Acreage				Acreage Subject to Expiration				Expiration Date Range
	Gross		Net		Gross		Net		Gross		Net
Williston		640		260		33,183		16,103		32,543		15,843	Range from 2012-2016
Denver -Julesberg		0		0		355		120		355		120	2012


Other		2,080		114		62,080		6,114		60,000		6,000	Range from 2012-2016

Total		2,720		374		95,618		22,337		92,898		21,963

As of July 6, 2012, we have approximately 22,337 net acres in Sheridan, Montana, Williams, Divide, Mountrail, and Stark, North Dakota, Sioux, Nebraska, and Weld, Colorado. The expiration of the majority of these leases ranges from 3 to 5 years and in some instances, the acreage has additional options to extend the lease maturity. We do not own the majority working interest in this acreage, nor do we have any ability to influence the potential development of this acreage within the terms of the lease. We are currently evaluating our options to selectively drill some of these leases to hold this acreage by production.

Our non-operated minority interest acreage is primarily not held by production as of today, with 21,963 of our 22,337 net acres undeveloped or subject to drilling in progress. Our acreage exposure is very granular; we hold 22 leases with a typical working or royalty interest ranging from less than 1% to 20%. We hold approximately 21,963 net acres that expire from 2012 to 2016 with the majority of the leases not having any extension options.

Competitive Advantage

We believe our competitive advantage is our streamlined operating model, which we believe may enable us to grow leasehold acquisition and acreage development at an accelerated pace in the future. We intend to utilize our capital to expand our lease holdings and contract with third party operators to drill our majority working interest leasehold acreage. By eliminating the staffing required to manage this process internally, we reduce our fixed employee cost structure and overhead. Further, utilizing a non-operator business model, we are not limited in acquisition size of leasehold acreage and participation. Therefore, we believe we have more opportunity to acquire smaller, but more numerous, leasehold acreage in and around prolific areas which will be beneficial for us but which are not preferred by larger, operating-oriented companies.

Employees

We currently have a full-time staff of 2 employees. We may selectively increase staff during the remainder of 2012, specifically in the area of land acquisition and accounting personnel.

Legal Proceedings

On May 18, 2012, we filed a complaint against Petrogulf Corporation in the U.S. District Court for the District of North Dakota alleging breach of an agreement to assign to us a non-operating, working interest in certain oil wells and oil & gas leases. We are seeking specific performance of the disputed agreement, an award of compensatory damages to be determined at trial, but in no event less than $50 million, plus interest, costs incurred in connection with this litigation and such relief as the court may deem proper. Petrogulf Corporation seeks declaratory judgment and monetary damages related to and arising from our complaint filing.

Regulatory Matters

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of our properties. Sales of condensate and oil and NGLs are not currently regulated and are made at market prices.

Drilling and Production

The operations of our properties are subject to various types of regulation at federal, state, and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities where our properties are operated also regulate one or more of the following activities:

●	the location of wells;

●	the method of drilling and casing wells;

●	the timing of construction or drilling activities including seasonal wildlife closures;

●	the rates of production or “allowables;”

●	the surface use and restoration of properties upon which wells are drilled;

●	the plugging and abandoning of wells; and

●	the notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, oil and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells, or to limit the number of locations our operating partners can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines, and for site restoration, in areas where our properties are operated. Most states have an administrative agency that requires the posting of performance bonds to fulfill financial requirements for owners and operators on state land. The Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price of the natural gas produced on our properties and the manner in which our production is marketed. The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that is produced by our properties, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing natural gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with them. The FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under the FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, the FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting natural gas to point-of-sale locations.

Oil Sales and Transportation

Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our crude oil sales may be affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect the operations of our properties in any way that is of material difference from those of our competitors. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operating partners to the same extent as to our competitors.

Environmental Matters

The operations of our properties are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Applicable U.S. federal environmental laws include, but are not limited to, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Clean Water Act (“CWA”) and the Clean Air Act (“CAA”). These laws and regulations govern environmental cleanup standards, require permits for air, water, underground injection, solid and hazardous waste disposal and set environmental compliance criteria. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters. We and our operating partners maintain insurance against costs of clean-up operations, but we and our operating partners are not fully insured against all such risks. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Public and regulatory scrutiny of the energy industry has resulted in increased environmental regulation and enforcement being either proposed or implemented. For example, in March 2010, the Environmental Protection Agency (the “EPA”) announced its National Enforcement Initiatives for 2011 to 2013, which includes the addition of “Energy Extraction Activities” to its enforcement priorities list. According to the EPA’s website, “some energy extraction activities, such as new techniques for oil and gas extraction and coal mining, pose a risk of pollution of air, surface waters and ground waters if not properly controlled.” To address these concerns, the EPA is developing an initiative to ensure that energy extraction activities are complying with federal environmental requirements. This initiative will be focused on those areas of the country where energy extraction activities are concentrated, and the focus and nature of the enforcement activities will vary with the type of activity and the related pollution problem presented. This initiative could involve a large scale investigation of our operating partners’ facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us and/or our operating partners.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Accidental releases or spills may occur in the course of the operations of our properties, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that our operating partners are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this will continue in the future.

The environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business are as follows:

Hazardous Substances and Wastes. CERCLA, also known as the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file corresponding common law claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

The Resource Conservation and Recovery Act (“RCRA”) generally does not regulate wastes generated by the exploration and production of natural gas and oil. The RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. An environmental organization recently petitioned the EPA to reconsider certain RCRA exemptions for exploration and production wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

We lease onshore properties that for a number of years have been used for or associated with the exploration and production of natural gas and oil. Although our operating partners may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, these properties, prior to our obtaining an interest therein, may have been operated by third parties whose treatment and disposal or release of wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, the CWA, the RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

Waste Discharges. The CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment beams and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. We believe that the operations of our properties are in substantial compliance with the CWA.

On February 16, 2012, the EPA issued the final 2012 construction general permit (“CGP”) for storm water discharges from construction activities involving more than one acre, which will provide coverage for a five year period. The 2012 CGP modifies the prior CGP to implement the new Effluent Limitations Guidelines and New Source Performance Standards for the Construction and Development Industry. The new rule includes new and more stringent restrictions on erosion and sediment control, pollution prevention and stabilization, although a numeric turbidity limit for certain larger construction sites has been stayed as of January 4, 2011.

Air Emissions. The CAA and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before construction can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. More stringent regulations governing emissions of toxic air pollutants and greenhouse gases (“GHGs”) have been developed by the EPA and may increase the costs of compliance for some facilities.

Oil Pollution Act. The Oil Pollution Act of 1990, as amended (“OPA”) and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.

Endangered Species Act. The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that our operations are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

Worker Safety. The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Safe Drinking Water Act. The Safe Drinking Water Act (“SDWA”) and comparable state statutes restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.

Hydraulic Fracturing. Our operating partners ordinarily use hydraulic fracturing as a means to maximize the productivity of our oil and gas wells in the basins in which our properties are located. Our net acreage position in the basins in which hydraulic fracturing is utilized total approximately 22,337 net acres and represents approximately 100% of our domestic proved undeveloped oil and gas reserves. The average drilling and completion costs for each basin will vary, as will the cost of each well within a given basin. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget.

The protection of groundwater quality is extremely important to us. We intend to require that our operating partners follow applicable standard industry practices and legal requirements for groundwater protection in operating our wells. These measures are subject to close supervision by state and federal regulators (including the BLM with respect to federal acreage), which conduct many inspections during operations that include hydraulic fracturing. Industry standards and legal requirements for groundwater protection focus on five principal areas: (i) pressure testing of well construction and integrity, (ii) lining of pits used to hold water and other fluids used in the drilling process isolated from surface water and groundwater, (iii) casing and cementing practices for wells to ensure separation of the production zone from groundwater, (iv) disclosure of the chemical content of fracturing liquids, and (v) setback requirements as to the location of waste disposal areas. The legal requirements relating to the protection of surface water and groundwater vary from state to state and there are also federal regulations and guidance that apply to all domestic drilling. In addition, the American Petroleum Institute publishes industry standards and guidance for hydraulic fracturing and the protection of surface water and groundwater. Our policy and practice will be to require our operating partners to follow all applicable guidelines and regulations in the areas where we conduct hydraulic fracturing.

In addition to the required use of and specifications for casing and cement in well construction, we expect that our operating partners will observe regulatory requirements and what they consider best practices to ensure wellbore integrity and full isolation of any underground aquifers and protection of surface waters. These may include some or all of the following:

●	Prior to perforating the production casing and hydraulic fracturing operations, the casing is pressure tested.

●

Before the fracturing operation commences, all surface equipment is pressure tested, which includes the wellhead and all pressurized lines and connections leading from the pumping equipment to the wellhead. During the pumping phases of the hydraulic fracturing treatment, specialized equipment is utilized to monitor and record surface pressures, pumping rates, volumes and chemical concentrations to ensure the treatment is proceeding as designed and the wellbore integrity is sound. Should any problem be detected during the hydraulic fracturing treatment, the operation is shut down until the problem is evaluated, reported and remediated.

●

As a means to protect against the negative impacts of any potential surface release of fluids associated with the hydraulic fracturing operation, special precautions are taken to ensure proper containment and storage of fluids. For example, any earthen pits containing non-fresh water must be lined with a synthetic impervious liner. These pits are tested regularly, and in certain sensitive areas have additional leak detection systems in place. At least two feet of freeboard, or available capacity, must be present in the pit at all times. In addition, earthen berms are constructed around any storage tanks, any fluid handling equipment, and in some cases around the perimeter of the location to contain any fluid releases. These berms are considered to be a “secondary” form of containment and serve as an added measure for the protection of groundwater.

●	Conduct baseline water monitoring in certain of the basins in which hydraulic fracturing is used:

In Colorado, baseline water monitoring may be required by the Colorado Oil and Gas Conservation Commission (“COGCC”) or BLM as a condition of approval for the drilling permit, but otherwise it is not a requirement. Industry worked with the Colorado Oil & Gas Association as well as the COGCC to adopt a voluntary baseline groundwater quality sampling program. Our operating partner in Colorado has committed to the program that went into effect in August 2011.

o	There are currently no regulatory requirements to conduct baseline water monitoring in the Bakken Shale. We expect our operating partners to voluntarily conduct water monitoring in the Bakken Shale.

Once a pipe is set in place, cement is pumped into the well where it hardens and creates a permanent, isolating barrier between the steel casing pipe and surrounding geological formations. This aspect of the well design essentially eliminates a “pathway” for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. Furthermore, in the basins in which our operating partners may conduct hydraulic fracturing, the hydrocarbon bearing formations are separated from any usable underground aquifers by thousands of feet of impermeable rock layers. This wide separation serves as a protective barrier, preventing any migration of fracturing fluids or hydrocarbons upwards into any groundwater zones.

In addition, the vendors our operating partners may employ to conduct hydraulic fracturing will likely be required to monitor all pump rates and pressures during the fracturing treatments. This monitoring typically occurs on a real-time basis and data is recorded to ensure protection of groundwater.

The cement and steel casing used in well construction can have rare failures. Any failure in isolation is reported to the applicable oil and gas regulatory body. A remediation procedure is written and approved and then completed on the well before any further operations or production is commenced. Possible isolation failures may result from:

●

Improper cementing work. This can create conditions in which hydraulic fracturing fluids and other natural occurring substances can migrate into the surrounding geological formation. Production casing cementing tops and cement bond effectiveness are evaluated using either a temperature log or an acoustical cement bond log prior to any completion operations. If the cement bond or cement top is determined to be inadequate for zone isolation, remedial cementing operations are performed to fill any voids and re-establish integrity. As part of this remedial operation, the casing is again pressure tested before fracturing operations are initiated.

●

Initial casing integrity failure. The casing is pressure tested prior to commencing completion operations. If the test fails due to a compromise in the casing, the applicable oil and gas regulatory body will be notified and a remediation procedure will be written, approved and completed before any further operations are conducted. In addition, casing pressures are monitored throughout the fracturing treatment and any indication of failure will result in an immediate shutdown of the operation.

●

Well failure or casing integrity failure during production. Loss of wellbore integrity can occur over time even if the well was correctly constructed due to downhole operating environments causing corrosion and stress. During production, the bradenhead, casing and tubing pressures are monitored and a casing failure can be identified and evaluated. Remediation could include placing additional cement behind casing, installing a casing patch, or plugging and abandoning the well, if necessary.

●

Fluid “leakoff” during the fracturing process. Fluid leakoff can occur during hydraulic fracturing operations whereby some of the hydraulic fracturing fluid flows through the artificially created fractures into the micropore or pore spaces within the formation, existing natural factures in the formation, or small fractures opened into the formation by the pressure in the induced fracture. Fluid leakoff is accounted for in the volume design of nearly every fracturing job and “pump-in” tests are often conducted prior to fracturing jobs to estimate the extent of fluid leakoff. In certain situations, a very fine grain sand is added in the initial part of the treatment to seal-off any small fractures of micropore spaces and mitigate fluid leak-off.

Approximately 99% of hydraulic fracturing fluids are made up of water and sand. Our operating partners utilize major hydraulic fracturing service companies whose research departments conduct ongoing development of “greener” chemicals that are used in fracturing. Our operating partners evaluate, test, and where appropriate adopt those products that are more environmentally friendly.

Recently, there has been a heightened debate over whether the fluids used in hydraulic fracturing may contaminate drinking water supply and proposals have been made to revisit the environmental exemption for hydraulic fracturing under the SDWA or to enact separate federal legislation or legislation at the state and local government levels that would regulate hydraulic fracturing. Both the United States House of Representatives and Senate are considering Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) bills and a number of states, including states in which we have operations, are looking to more closely regulate hydraulic fracturing due to concerns about water supply. A committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. The recent congressional legislative efforts seek to regulate hydraulic fracturing to Underground Injection Control program requirements, which would significantly increase well capital costs. If the exemption for hydraulic fracturing is removed from the SDWA, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.

Federal agencies are also considering regulation of hydraulic fracturing. The EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, the EPA’s interpretation without formal rule making has been challenged and industry groups have filed suit challenging the EPA’s interpretation. If the EPA prevails in this lawsuit, its interpretation could result in enforcement actions against service providers or companies that used diesel products in the hydraulic fracturing process or could require such providers or companies to conduct additional studies regarding diesel in the groundwater.

On October 21, 2011, the EPA announced its intention to propose regulation by 2014 under the CWA to regulate wastewater discharges from hydraulic fracturing and other natural gas production. The EPA is also collecting information as part of a study into the effects of hydraulic fracturing on drinking water. The results of this study, expected in late 2012, could result in additional regulations, which could lead to operational burdens similar to those described above.

In addition to the EPA study, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board issued a report on hydraulic fracturing in August 2011. The report concludes that the risk of fracturing fluids contaminating drinking water sources through fractures in the shale formations “is remote.” It also states that development of the nation’s shale resources has produced major economic benefits. The report includes recommendations to address concerns related to hydraulic fracturing and shale gas production, including but not limited to conducting additional field studies on possible methane leakage from shale gas wells to water reservoirs and adopting new rules and enforcement practices to protect drinking and surface waters. The Government Accountability Office is also examining the environmental impacts of produced water and the Counsel for Environmental Quality has been petitioned by environmental groups to develop a programmatic environmental impact statement under the National Environmental Policy Act for hydraulic fracturing. The United States Department of the Interior is also considering whether to impose disclosure requirements or other mandates for hydraulic fracturing on federal land.

Several states, including Colorado and North Dakota, have adopted or are considering adopting, regulations that could restrict or impose additional requirements related to hydraulic fracturing. Since June 2009, Colorado has required all operators to maintain a chemical inventory by well site for each chemical product used downhole or stored for use downhole during drilling, completion and workover operations, including fracture stimulation in an amount exceeding 500 pounds during any quarterly reporting period. Colorado adopted its final hydraulic fracturing chemical disclosure rules on December 13, 2011. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

Global Warming and Climate Change. Recent scientific studies have suggested that emissions of Green House Gases (GHGs), including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere. Both houses of Congress have previously considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The EPA has begun to regulate GHG emissions. On December 7, 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. EPA issued a final rule that went into effect in 2011 that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions. On November 30, 2010, the EPA published its final rule expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage, and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. Several of the EPA’s GHG rules are being challenged in court proceedings and depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact our operations. In addition to these regulatory developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against GHG emissions sources and may increase our litigation risk for such claims. New legislation or regulatory programs that restrict emissions of or require inventory of GHGs in areas where we operate may adversely affect our operations by increasing costs.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs 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 adversely affect or delay demand for the oil or natural gas or otherwise cause us to incur significant costs in preparing for or responding to those effects.

Available Information

We are subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Reports filed with the SEC pursuant to the Exchange Act, including annual and quarterly reports, and other reports we file, can be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Investors may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. Investors can request copies of these documents upon payment of a duplicating fee by writing to the SEC. The reports we file with the SEC are also available on the SEC’s website (http://www.sec.gov).

RISK FACTORS AND SPECIAL CONSIDERATIONS

Information provided in this Current Report on Form 8-K may contain forward-looking statements which reflect management’s current view with respect to future events, the viability or efficacy of our products and our future performance. Such forward-looking statements may include projections with respect to market size and acceptance, revenues and earnings, marketing and sales strategies and business operations, as well as efficacy of our products.

You should carefully consider each of the following risks, which we believe are the principal risks that we face and of which we are currently aware, and all of the other information in this report. Some of the risks described below relate to our business. Other risks relate principally to the securities markets and ownership of our Common Stock. If any of the following risks actually occur, our business, financial condition, cash flows and results of operations could suffer materially and adversely. In that case, the trading price of our common stock could decline, and you might lose all or part of your investment.

Risks related to our Business

We have a limited operating history and a history of operating losses, and expect to incur significant additional operating losses.

We were incorporated in 2011, and were initially funded by our founders and officers and accredited outside investors. Therefore, there is limited historical financial information upon which to base an evaluation of our performance. Our prospects must be considered in light of the uncertainties, risks, expenses, and difficulties frequently encountered by companies in their early stages of operations. We have generated operating losses since we began operations, including $984,559 for the year ended December 31, 2011, and $1,117,904 (unaudited) for the first six months of 2012, and as of June 30, 2012 we had an accumulated operating loss of $2,102,463 (unaudited). We cannot assure you that we will be successful in addressing the risks we may encounter, and our failure to do so could have a material adverse effect on our business, prospects, financial condition and results of operations. Our future operating results will depend on many factors, including:

●	our ability to raise adequate working capital;

●	the successful development and exploration of our properties;

●	demand for oil and natural gas;

●	the performance level of our competition;

●	our ability to attract and maintain key management and employees; and

●	our ability to efficiently explore, develop and produce sufficient quantities of marketable natural gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

Our business is speculative and dependent upon the implementation of our business plan and our ability to enter into agreements with third parties for the rights to exploit potential oil and natural gas reserves on terms that will be commercially viable for us. To achieve profitable operations in the future, we must, alone or with others, successfully manage the factors stated above, as well as continue to develop ways to enhance our production efforts. Despite our best efforts, we may not be successful in our exploration or development efforts, or obtain required regulatory approvals. There is a possibility that some of our wells may never produce oil or natural gas.

We are dependent on the skill, ability and decisions of third party operators.

We do not operate any of our properties. The success of the drilling, development, production and marketing of the oil and natural gas from our properties is dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of any third-party operator to make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and comply with laws, rules and regulations, including environmental laws and regulations in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could negatively affect our results of operations.

Our operators may be unable to renew or maintain contracts with independent purchasers, which would harm our business and financial results.

Upon expiration of our independent purchasers’ contracts, we are subject to the risk that the oil and natural gas purchasers will cease buying our oil and gas production output. It is not always possible for our operators to immediately obtain replacement oil and natural gas purchasers as the industry is extremely competitive. If these contracts are not renewed, it could result in a significant negative impact on our business.

The possibility of a global financial crisis may significantly impact the company’s business and financial condition for the foreseeable future.

The credit crisis and related turmoil in the global financial system may adversely impact our business and financial condition, and we may face challenges if conditions in the financial markets remain challenging. Our ability to access the capital markets may be restricted at a time when we would prefer or be required to raise financing. Such constraints could have a material negative impact on our flexibility to react to changing economic and business conditions. The economic situation could also have a material negative impact on the operators upon whom we are dependent on for drilling our wells, and our lenders, causing us to fail to meet our obligations to them or for them to fail to meet their obligations to us. Additionally, market conditions could have a material negative impact on any crude oil hedging arrangements we may employ in the future if our counterparties are unable to perform their obligations or seek bankruptcy protection.

Our future is entirely dependent on the successful acquisition and development of producing and reserve rich properties.

We are in the early stages of the acquisition of our portfolio of leaseholds and other natural resource holdings. We will continue to supplement our current portfolio with additional sites and leaseholds. Our ability to meet our growth and operational objectives will depend on the success of our acquisitions, and there is no assurance that the integration of future assets and leaseholds will be successful.

Our lack of diversification will increase the risk of an investment in us, and our financial condition and results of operations may deteriorate if we fail to diversify.

Our business focus is on the oil and gas industry and initially, our core operating areas are the Williston Basin in North Dakota and Montana and the Denver-Julesburg Basin in Colorado. In the Williston Basin, we focus on oil production from multiple zones including the Bakken Shale, and Three Forks Sanish Formations. In Colorado we focus on the Niobrara Formations. Larger companies have the ability to manage their risk by greater diversification. However, we may lack comparable diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if we were a more diversified business, enhancing our risk profile. If we do not diversify our operations, our financial condition and results of operations could deteriorate.

We will likely need to raise additional capital.

We expect to be able to fund our 2012 capital budget partially with operating cash flows and debt and/or equity financings. We will require additional capital to continue to grow our business via the drilling program through our third-party operators associated with our current properties and expansion of our exploration and development and leasehold acquisition programs. We may be unable to obtain additional capital if and when required.

Future acquisitions and future exploration and development activity will require additional capital that may exceed operating cash flow. In addition, our administrative costs (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require cash resources.

We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the required capital by other means. If we are not successful in raising additional capital, our resources may be insufficient to fund our planned expansion of operations in 2012 or thereafter.

Any additional capital raised through the sale of equity may dilute the ownership percentage of our stockholders. Raising any such capital could also result in a decrease in the nominal fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to new investors and may include preferences, superior voting rights, the issuance of other derivative securities and issuances of incentive awards under equity employee incentive plans, all of which may have a dilutive effect to existing investors.

There is currently outstanding $250,000 principal amount of Stratex convertible promissory notes (the “Stratex Notes”). The Stratex Notes, which bear interest, are due and payable at various dates from October 24, 2012 to January 30, 2013 unless earlier converted into our Common Stock, of which there can be no assurance. We may require additional financing to retire the Stratex Notes at maturity to the extent they are not converted into Common Stock.

Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), our limited operating history, the location of our oil and natural gas properties, prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and the departure of key employees. Further, if oil or natural gas prices decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with revenues from our operations, are not sufficient to satisfy our capital needs (even if we reduce our operations), we may be required to cease operations, divest our assets at unattractive prices or obtain financing on unattractive terms.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct operations.

Our ability to acquire additional leaseholds successfully, to increase our oil and natural gas reserves, to participate in drilling opportunities through our third party operators and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants, and our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. Our inability to maintain close working relationships with industry participants or continue to acquire suitable leaseholds may impair our ability to execute our business plan.

To continue to develop our business, we will endeavor to use the business relationships of members of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and gas companies, including those that supply equipment and other resources which we may use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them adequately. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. For example, we may hold minority interests in a lease that has significant existing or prospective value due to current production or future reserve prospects. We may be subject to contracts with a third-party operator that compel us to make certain financial commitments on that lease, otherwise we may be at risk of forfeiting existing or future rights to petroleum production from that lease if we fail to meet those financial obligations. Such provisions may be included in any third party joint operating agreement, or JOA, drilling program under an area of mutual interest (AMI), or other joint venture projects which are common in our industry. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

We must reach agreements with third-party professionals and experts to supply us with the expertise, services and infrastructure necessary to operate our business, and the loss of access to these experts, these services and infrastructure could cause our business to suffer, which, in turn, could decrease our revenues and increase our costs.

We have certain contemplated strategic vendor relationships that will be critical to our strategy. As a non-operator, we must actively secure the services of drilling companies, hydrofracking and completion companies, contract operators, engineers and other service providers. We cannot assure that these relationships can be maintained or obtained on terms favorable to us. Our success depends substantially on obtaining relationships with additional strategic partners, such as investment banks, accounting firms, legal firms and operational entities. If we are unable to obtain or maintain relationships with strategic partners, our business, prospects, financial condition and results of operations may be materially adversely affected.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on such acreage or the leases are extended.

Our leases on certain undeveloped leasehold acreage may expire over the next one to eight years. A portion of our acreage is not currently held by production. Unless production in paying quantities is established on acres containing these leases during their initial terms or we obtain extensions of the leases, these leases will expire. If our leases expire, we will lose our right to develop the related properties covered by such leases.

We are dependent on certain key personnel. The loss of such personnel could impair our ability to fulfill our business plan.

We are dependent on the services of Stephen Funk, our Chief Executive Officer, and Timothy Kelly, our President and Chief Operating Officer. The loss of services of any of these individuals could impair our ability to complete acquisitions of producing assets and leaseholds, perform relevant managerial and legal services and maintain key relationships with market participants which could have a material adverse effect on our business, financial condition and results of operations.

We need to continue to develop and maintain a diverse portfolio of leaseholds and producing properties; otherwise we will be unable to effectively compete in the industry.

To remain competitive, we must continue to enhance and improve our oil and natural gas reserves and producing properties and leaseholds. We need to seek available properties and leaseholds in various locations including the Bakken Shale, Three Forks, and Niobrara formations, the Williston Basin and Denver-Julesburg Basin, among others. These efforts may require us to choose one available property in lieu of another which increases risk to our potential holdings. If we are unable to maintain a diverse portfolio of leasehold properties, we will be unable to compete effectively and may be negatively impacted financially if our leasehold properties in a certain location are unable to produce.

Market conditions or transportation impediments may hinder access to oil and natural gas markets or delay production.

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations by our third party operators may restrict our access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas, the proximity of reserves to pipelines or trucking and terminal facilities and the availability of trucks and other transportation equipment. The operators we contract or partner with may be required to shut-in wells or delay initial production for lack of a viable market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

Risks related to the Oil and Natural Gas Industry

Crude oil and natural gas prices are very volatile. A protracted period of depressed oil and natural gas prices may adversely affect our business, financial condition, results of operations or cash flows.

The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The prices we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves. The prices we receive for our production and the levels of our production and reserves depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

changes in global supply and demand for oil and natural gas by both refineries and end users;

the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

the price and volume of imports of foreign oil and natural gas;

political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;

the level of global oil and gas exploration and production activity;

the level of global oil and gas inventories;

weather conditions;

technological advances affecting energy consumption;

domestic and foreign governmental regulations and taxes;

proximity and capacity of oil and gas pipelines and other transportation facilities;

the price and availability of competitors’ supplies of oil and gas in captive market areas;

	·	the introduction, price and availability of alternative forms of fuel to replace or compete with oil and natural gas;
	·	speculation in the price of commodities in the commodity futures market;
	·	the availability of drilling rigs and completion equipment; and
	·	the overall economic environment.

Further, oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 100% of our estimated proved reserves as of December 31, 2011 were oil, our financial results are more sensitive to fluctuations in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue for the foreseeable future. The slowdown in economic activity caused by the worldwide economic recession has reduced worldwide demand for energy. This may result in lower crude oil and natural gas prices. Crude oil prices declined from record high levels in early July 2008 of over $140 per Bbl to below $45 per Bbl in February 2009 before rebounding to over $105 per Bbl in March 2012. Natural gas prices declined from over $13 per MMBtu in mid-2008 to approximately $2.5 per MMBtu in March 2012. Such a decline could occur again in the future due to global economic conditions.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our reserve bookings. A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures; we will be required to reduce spending or borrow to cover any such shortfall.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties. The occurrence of any of these uncertainties may adversely affect our financial condition.

Our future success will depend on the success of our exploration, development, and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Our decision to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost associated with drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

delays imposed by or resulting from compliance with regulatory requirements;

pressure or irregularities in geological formations;

shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and CO2;

equipment failures or accidents;

	·	adverse weather conditions, such as freezing temperatures, hurricanes and storms;
	·	unexpected operational events;
	·	reductions in oil and natural gas prices;
	·	proximity to and capacity of transportation facilities;
	·	title problems; and

The presence of one or a combination of these factors at our properties could adversely affect our business, financial condition or results of operations.

Estimates of oil and natural gas reserves that may be inaccurate and actual quantity of our proved oil and natural gas reserves may be lower than the company’s projections.

We make estimates of oil and natural gas reserves, upon which we have and will base our management decisions. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, timing of operations and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates rely in part on the ability of our management team, engineers and other advisors to make accurate assumptions.

Determining the amount of oil and gas recoverable from various formations where we have exploration and production activities involves great uncertainty. The process of estimating oil and natural gas reserves is complex and will require us to make significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. These assumptions are dependent on many variables, and therefore changes often occur as these variables evolve. As a result, our reserve estimates will be inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from our estimates. Although we have estimated our reserves and the costs associated with these reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and could result in the impairment of our oil and natural gas properties.

The 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 revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements for the year ended December 31, 2011, we based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

•

actual prices we receive for oil and natural gas;

•

actual cost of development and production expenditures;

•

the amount and timing of actual production; and

•

changes in governmental regulations or taxation.

The timing of both our production and our incurring expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Actual future prices and costs may differ materially from those used in the present value estimates included in this Current Report on Form 8-K. Any significant future price changes will have a material effect on the quantity and present value of our proved reserves.

We will rely on technology to conduct our business, and such technology could become ineffective or obsolete which would result in substantial costs to us.

Our industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities. We must continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial and may be higher than the costs that we anticipate for technology maintenance and development. In addition, other natural gas and crude oil companies may 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 may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired and our business, financial condition and results of operations could be materially adversely affected. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than if our technology was more efficient.

A decline of oil and natural gas prices or a prolonged period of reduced oil and natural gas prices could result in a decrease in our exploration and development expenditures, which could negatively impact our future production.

If oil and natural gas prices decline or reduce to lower levels for a prolonged period of time, we may be unable to continue to fund capital expenditures at historical levels due to the decreased cash flows that will result from such reduced oil and natural gas prices. Additionally, a decline in oil and natural gas prices or a prolonged period of lower oil and natural gas prices could result in a reduction of our borrowing base under any credit facility we might obtain in the future, which would further reduce the availability of cash to fund our operations. As a result, we may have to reduce our capital expenditures in future years. A decrease in our capital expenditures will likely result in a decrease in our production levels.

Continued weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.

U.S. and global economies and financial systems have experienced episodes of turmoil and upheaval characterized by extreme volatility in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of financial institutions, and continue to be affected by continued high levels of unemployment and an unprecedented level of intervention by the U.S. federal and other governments. Continued weakness in the U.S. or global economies could materially adversely affect our business and financial condition. For example:

•

the demand for oil and natural gas in the U.S. may decline from present levels and may remain at low levels if economic conditions remain weak, and negatively impact our revenues, margins, profitability, operating cash flows, liquidity and financial condition;

•

the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

•

our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for exploration and/or development of our reserves.

The oil and gas industry is subject to substantial competition. If we are unable to compete effectively, our financial condition may be adversely affected.

The oil and gas industry is highly competitive. Other oil and gas companies may seek to acquire oil and natural gas leases and other properties and services the Company requires to operate its business in the planned areas. This competition is increasingly intense as prices of oil and natural gas have risen in recent years. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger companies who may have access to greater financial, technical and personnel resources and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. Existing or potential competitors 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 over the past few years due to competition and may increase substantially in the future. In addition, existing or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or respond adequately to competitive pressures, our results of operation and financial condition may be materially adversely affected.

Our business of exploring for oil and gas is risky and may not be commercially successful, and the advanced technologies the company uses cannot eliminate exploration risk.

Our future success will depend on the success of our exploratory drilling program through our third party operators. Oil and gas exploration and development involves a high degree of risk. These risks are more acute in the early stages of exploration.

Our expenditures on exploration may not result in new discoveries of oil or natural gas in commercially viable quantities. Projecting the costs of implementing an exploratory drilling program is difficult due to a variety of factors, including:

the inherent uncertainties of drilling in less known formations;

the costs associated with encountering various and unexpected drilling conditions, such as over-pressured zones;

equipment failures or accidents and shortages or delays in the availability of oilfield services or drilling rigs and other equipment;

changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof;

adverse weather conditions, including hurricanes; and

compliance with governmental requirements.

Even when used and properly interpreted, three-dimensional (3-D) seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. Such data and techniques do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of three-dimensional (3-D) seismic data becomes less reliable when used at increasing depths. We could incur losses as a result of expenditures on unsuccessful wells. If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.

We may not be able to develop oil and gas reserves on an economically viable basis and our reserves and production may decline as a result.

If we succeed in discovering oil or natural gas reserves, we cannot assure that these reserves will be capable of the production levels we project or that such levels will be in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future performance will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to distribute effectively our production into the markets.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, we cannot assure you we will do so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and could result in the impairment of our oil and natural gas properties.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and natural gas reserves, and ultimately our profitability.

Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas and crude oil reserves. To date, we have financed capital expenditures primarily with proceeds from our private placement offerings of our securities. We intend to finance our future capital expenditures utilizing similar financing sources as well as from bank credit facilities, if available to us. Our cash flows from operations are subject to a number of variables, including:

our proved reserves;

the amount of oil and natural gas we are able to produce from existing wells;

the prices at which oil and natural gas are sold;

the costs to produce oil and natural gas; and

our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under any credit facilities we obtain in the future decreases as a result of lower natural gas and crude oil prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. If we raise funds by issuing equity securities (including convertible debt instruments), this could have a dilutive effect on existing stockholders. There can be no assurance as to the availability or terms of any additional financing. Our inability to obtain additional financing, including bank credit facilities, or sufficient financing on favorable terms, would adversely affect our financial condition and profitability.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

We intend to review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under any revolving credit facility we might obtain and our results of operations for the periods in which such charges are taken.

We intend to outsource the operation of our drilling locations, and, therefore, in certain situations we will not be able to control, and in other situations we will have limited input regarding, the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

We intend to enter into contract operating agreements with operators who will be responsible for the management and day-to-day operation of our crude oil and/or natural gas wells. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operators could prevent us from realizing our target returns. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

•

the timing and amount of capital expenditures;

•

the operator’s expertise and financial resources;

•

approval of other participants in drilling wells;

•

selection of technology; and

•

the rate of production of reserves, if any.

This limited ability to exercise control over the operations of our drilling locations may cause a material adverse effect on our results of operations and financial condition.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

We had no proved reserves which were classified as proved undeveloped as of December 31, 2011. Development of such reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Drilling new wells could result in new liabilities, which could endanger our interests in our properties and assets. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among others. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. We intend to do our best to insure ourselves with respect to these hazards; however, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We may have to accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

We may have difficulty distributing our production, which could harm our financial condition.

In order to sell the oil and natural gas that are produced from our properties, the operators of our wells may have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This situation could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to explore and develop properties and to store and transport our oil and natural gas production and may increase our expenses.

Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we operate, or labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

Our potential drilling location inventories may be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.

Our management has identified drilling locations on our existing acreage. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Certain acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. We had no leases acreage that expired during 2011, and 21,963 net acres expiring from 2012 to 2016. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

Future derivative activities could result in financial losses or could reduce our income.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designated any derivative instruments as hedges for accounting purposes and expect to record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Derivative arrangements may also expose us to the risk of financial loss in some circumstances, including when:

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production is less than the volume covered by the derivative instruments;

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the counterparty to the derivative instrument defaults on its contract obligations; or

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there is an increase in the differential between the underlying price in the derivative instrument and actual price received.

In addition, some of these types of derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.

The recent adoption of derivatives legislation by the United States congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if commodity prices decline as a consequence of the legislation and regulations. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.

We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

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recoverable reserves;

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future oil and natural gas prices and their appropriate differentials;

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development and operating costs; and

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potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Significant acquisitions and other strategic transactions may involve other risks, including:

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diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

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the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

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difficulty associated with coordinating geographically separate organizations; and

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the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be lower than we expect.

The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

Our business may suffer if we cannot obtain or maintain necessary licenses.

Our operations require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to changes in regulations and policies and to the discretion of the applicable governments, among other factors. Our inability to obtain, or the loss of or denial of extension of, any of these licenses or permits could result in our inability to utilize certain of our leasehold properties or wells and would therefore diminish our ability to produce revenue.

Challenges to our leaseholds properties may impact the company’s financial condition.

Title to oil and gas properties is often not capable of conclusive determination without incurring substantial expense. To mitigate title problems, common industry practice is to obtain a title opinion from a qualified oil and gas attorney prior to the drilling operations of a well. While we intend to make appropriate inquiries into the title of properties and other development rights and obtain a title opinion when we acquire leaseholds, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the leasehold properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired.

Our operations are subject to various governmental regulations that require compliance that can be burdensome and expensive.

Our operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge from drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. These laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management, and compliance with these laws may cause delays in the additional drilling and development of our properties. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. While historically we have not experienced any material adverse effect from regulatory delays, there can be no assurance that such delays will not occur in the future.

Environmental risks may adversely affect our business.

All phases of the oil and gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures, and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.

Unusual weather patterns or natural disasters whether due to climate change or otherwise, could negatively impact our financial condition.

Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices. In addition, at least some of our operations are constantly at risk of extreme adverse weather conditions such as hurricanes and tornadoes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as hurricanes or floods, whether due to climate change or otherwise.

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, droughts, floods and other climatic events. If any such effects were to occur, they could have a material adverse effect on our financial condition and results of operations. Changes in climate due to global warming trends could adversely affect our operations by limiting or increasing the costs associated with equipment or product supplies. In addition, flooding and adverse weather conditions such as increased frequency and/or severity of hurricanes could impair our ability to operate in affected regions of the country. Repercussions of severe weather conditions may include: curtailment of services; weather-related damage to facilities and equipment, resulting in suspension of operations; inability to deliver equipment, personnel and products to job sites in accordance with contract schedules; and loss of productivity. These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters may decrease the demand for our oil or natural gas.

Government regulations and legal uncertainties could adversely affect the development and exploration of oil, gas, and other natural resources, thereby hindering our ability to produce revenue.

A number of potential legislative and regulatory proposals under consideration by federal, state, local and foreign governmental organizations may lead to laws or regulations concerning various aspects of oil, natural gas and other natural resources including within the primary geographic areas in which we hold properties. The adoption of new laws or the application of existing laws may decrease the growth in the demand or the cost of exploring for and developing natural resources which could in turn decrease the usage and demand for our production or increase our cost of doing business.

The recent trend in environmental legislation and regulation generally is toward stricter standards. These laws and regulations including the Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”), the Federal Resource Conservation and Recovery Act (“RCRA”) and the Endangered Species Act (“ESA”) may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from its operations. If operations of our properties are found to be in violation of any of the laws and regulations to which we are subject, we may be subject to the applicable penalty associated with the violation, including civil and criminal penalties, damages, fines and the curtailment of operations. Any penalties, damages, fines or curtailment of operations, individually or in the aggregate, could adversely affect our ability to operate our business and our financial results. In addition, many of these laws and regulations have not been fully interpreted by the regulatory authorities or the courts, and their provisions are open to a variety of interpretations. Any action against us for violation of these laws or regulations, even if we successfully defend against it, could cause us to incur significant legal expenses and divert management’s attention from the operation of our business.

Additionally, hydraulic fracturing, the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high pressure into the formation, is currently used in completing greater than 90% of all oil and natural gas wells drilled in the United States. While hydraulic fracturing is typically regulated by state oil and gas commissions, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents for permitting authorities and the industry on the process for obtaining a permit for hydraulic fracturing involving diesel fuel. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. Also, for the second consecutive session, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. We cannot predict whether additional hydraulic fracturing federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, our operations with respect to our leasehold properties could be subject to delays, increased operating and compliance costs and process prohibitions. Restrictions on hydraulic fracturing could also reduce the amount of oil, natural gas liquids and natural gas that we are ultimately able to produce in commercial quantities from our leasehold properties.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Legislation was proposed in the last Congress to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. We expect that third parties will be engaged to provide hydraulic fracturing or other well stimulation services in connection with many of the wells for the operators. If similar legislation is ultimately adopted, it could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

In addition to possible future regulatory changes at the federal level, several states (including Arkansas, Colorado, New York and Pennsylvania), have considered, or are considering, legislation or regulations similar to the federal legislation described above. Recently, for example, the Wyoming Oil and Gas Conservation Commission passed a rule requiring disclosure of hydraulic fracturing fluid content. At this time, it is not possible to estimate the potential impact on our business of additional federal or state regulatory actions affecting hydraulic fracturing. In addition, a number of states in which we plan to conduct hydraulic fracturing operations are currently conducting, or may in the future conduct, regulatory reviews that potentially could restrict or limit our access to shale formations located in their states. In most states, our third party operators are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities, including hydraulic fracturing. Such permits are typically required by state agencies, but can also be required by federal and local governmental agencies. The requirements for such permits vary depending on the location where such drilling and completion activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued and the conditions which may be imposed in connection with the granting of the permit. Recently, moratoriums on the issuance of permits have been imposed upon inland drilling and completion activities. For example, subject to an Executive Order issued by Governor Paterson on December 13, 2010, the New York Department of Environmental Conservation will not issue permits for drilling and completion activities until it completes a final environmental impact study following public comment. Wyoming and Colorado have enacted additional regulations applicable to our business activities. Arkansas is presently considering similar regulations. Some of the drilling and completion activities may take place on federal land, requiring leases from the federal government to conduct such drilling and completion activities. In some cases, federal agencies have cancelled oil and natural gas leases on federal lands.

In March 2010, the United States Environmental Protection Agency announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. Interim results of the study are expected in 2012, with final results expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Certain United States federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of proposed legislation, and therefore slow the demand for investment in the company’s industry.

President Obama’s Proposed Fiscal Year 2012 Budget includes proposals that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to the Company. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

In addition to other climate-related risks set forth in this “Risk Factors” section, we are and will be, directly and indirectly, subject to the effects of climate change and may, directly or indirectly, be affected by government laws and regulations related to climate change. We cannot predict with any degree of certainty what effect, if any, possible climate change and new and developing government laws and regulations related to climate change will have on our operations, whether directly or indirectly. While we believe that it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on our business, we believe that climate change and government laws and regulations related to climate change may affect, directly or indirectly, (i) the cost of the equipment and services we purchase, (ii) our ability to continue to operate as we have in the past, including drilling, completion and operating methods, (iii) the timeliness of delivery of the materials and services we need and the cost of transportation paid by us and our vendors and other providers of services, (iv) insurance premiums, deductibles and the availability of coverage, and (v) the cost of utility services, particularly electricity, in connection with the operation of our properties. In addition, climate change may increase the likelihood of property damage and the disruption of our operations, especially in coastal states. As a result, our financial condition could be negatively impacted by significant climate change and related governmental regulation, and that impact could be material.

Regulation and recent court decisions related to greenhouse gas emissions could have an adverse effect on our operations and demand for oil and natural gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that requires reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and several counties including the European Union have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatory programs.

The EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA issued a final rule requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. Our oil and natural gas operations are subject to such greenhouse gas reporting requirements and we will monitor our emissions to make such required reports when due in 2012. While we believe that we will be able to substantially comply with such reporting requirements without any material adverse effect to our financial condition, since such reporting requirements with respect to greenhouse gas emissions are new in the oil and gas industry, there can be no assurance that our reports will initially be in substantial compliance or that such requirements will not develop into more stringent and costly obligations that may have a significant impact on our operating costs. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has proposed such greenhouse gas regulations and may issue final rules this year.

In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas that we produce.

Risks Related to Our Common Stock and Liquidity Risks

Our securities are a “Penny Stock" and subject to specific rules governing their sale to investors

The SEC has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for the purposes relevant to our Common Stock, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require that a broker or dealer approve a person’s account for transactions in penny stocks; and the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must obtain financial information and investment experience objectives of the person; and make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form sets forth the basis on which the broker or dealer made the suitability determination; and that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors sell shares of our common stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

There is no recent trading activity in our Common Stock and there is no assurance that an active market will develop in the future.

There is no recent trading activity in our Common Stock. Further, although our Common Stock is currently quoted on the OTC Bulletin Board, trading of our Common Stock may be extremely sporadic. For example, several days may pass before any shares may be traded. As a result, an investor may find it difficult to dispose of, or to obtain accurate quotations of the price of our Common Stock. There can be no assurance that a more active market for our Common Stock will develop, or if one should develop, there is no assurance that it will be sustained. This severely limits the liquidity of our Common Stock, and would likely have a material adverse effect on the market price of our Common Stock and on our ability to raise additional capital.

Because we became public by means of a “reverse merger” we may not be able to attract the attention of brokerage firms.

Additional risks may exist since we became public through a “reverse merger.” Securities analysts of brokerage firms may not provide coverage of us since there is little incentive to brokerage firms to recommend the purchase of our Common Stock. No assurance can be given that brokerage firms will want to conduct any secondary offerings on our behalf in the future.

Compliance with the reporting requirements of federal securities laws can be expensive.

We are a public reporting company in the United States, and accordingly, subject to the information and reporting requirements of the Exchange Act and other federal securities laws, and the compliance obligations of the Sarbanes-Oxley Act. The costs of preparing and filing annual and quarterly reports and other information with the SEC and furnishing audited reports to stockholders are substantial.

Applicable regulatory requirements, including those contained in and issued under the Sarbanes-Oxley Act of 2002, may make it difficult for us to retain or attract qualified officers and directors, which could adversely affect the management of its business and its ability to obtain or retain listing of our Common Stock.

We may be unable to attract and retain those qualified officers, directors and members of board committees required to provide for effective management because of the rules and regulations that govern publicly held companies, including, but not limited to, certifications by principal executive officers. The enactment of the Sarbanes-Oxley Act has resulted in the issuance of a series of related rules and regulations and the strengthening of existing rules and regulations by the SEC, as well as the adoption of new and more stringent rules by the stock exchanges. The perceived increased personal risk associated with these changes may deter qualified individuals from accepting roles as directors and executive officers.

Further, some of these changes heighten the requirements for board or committee membership, particularly with respect to an individual’s independence from the corporation and level of experience in finance and accounting matters. We may have difficulty attracting and retaining directors with the requisite qualifications. If we are unable to attract and retain qualified officers and directors, the management of our business and our ability to obtain or retain listing of our shares of Common Stock on any stock exchange (assuming we elect to seek and are successful in obtaining such listing) could be adversely affected.

We may have undisclosed liabilities and any such liabilities could harm our revenues, business, prospects, financial condition and results of operations.

Even though our pre-merger assets and liabilities were transferred to the Split-Off Shareholder in the Split-Off, there can be no assurance that we will not be liable for any or all of such liabilities. Any such liabilities that survived the Merger and could harm our revenues, business, prospects, financial condition and results of operations upon our acceptance of responsibility for such liabilities.

The transfer of the operating assets and liabilities to PSOS, coupled with the Split-Off of PSOS, will result in taxable income to us in an amount equal to the difference between the fair market value of the assets transferred and the pre-merger tax basis of the assets. Any gain recognized, to the extent not offset by our net operating loss carryforward, if any, will be subject to federal income tax at regular corporate income tax rates.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or detect fraud. Consequently, investors could lose confidence in our financial reporting and this may decrease the trading price of our stock.

We must maintain effective internal controls to provide reliable financial reports and detect fraud. We have been assessing our internal controls to identify areas that need improvement. We are in the process of implementing changes to internal controls, but have not yet completed implementing these changes. Failure to implement these changes to our internal controls or any others that it identifies as necessary to maintain an effective system of internal controls could harm our operating results and cause investors to lose confidence in our reported financial information. Any such loss of confidence would have a negative effect on the trading price of our stock.

The price of our Common Stock may become volatile, which could lead to losses by investors and costly securities litigation.

The trading price of our Common Stock is likely to be highly volatile and could fluctuate in response to factors such as:

·	actual or anticipated variations in our operating results;

·	strategic actions by us or our competitors;

·	announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;

·	regulatory actions regarding our products;

·	announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;

·	adoption of new accounting standards affecting the our industry;

·	additions or departures of key personnel;

·	terrorist acts;

·	introduction of new products by us or our competitors;

·	sales of the our Common Stock or other securities in the open market; and

·	other events or factors, many of which are beyond our control.

The stock market is subject to significant price and volume fluctuations. In the past, following periods of volatility in the market price of a company’s securities, securities class action litigation has often been initiated against such a company. Litigation initiated against us, whether or not successful, could result in substantial costs and diversion of our management’s attention and resources, which could harm our business and financial condition.

Investors may experience dilution of their ownership interests because of the future issuance of additional shares of our Common Stock.

In the future, we may issue additional authorized but previously unissued equity securities, resulting in the dilution of the ownership interests of our present stockholders. We may also issue additional shares of our Common Stock or other securities that are convertible into or exercisable for our Common Stock in connection with hiring or retaining employees, future acquisitions, future sales of our securities for capital raising purposes, or for other business purposes. The future issuance of any such additional shares of Common Stock may create downward pressure on the trading price of our Common Stock. There can be no assurance that the we will not be required to issue additional shares, warrants or other convertible securities in the future in conjunction with any capital raising efforts, including at a price (or exercise prices) below the price at which shares of our Common Stock is currently quoted on the OTC Bulletin Board.

The concentration of our capital stock ownership with our founders, executive officers and director will limit your ability to influence corporate matters.

Our officers and directors beneficially own 100% of our outstanding shares of Series A Preferred Stock. Each share of Series A Preferred Stock has 1,000,000 times that number of votes on all matters submitted to stockholders that each share of common stock is entitled to vote at each meeting of stockholders with respect to any and all matters presented to our stockholders for their action or consideration including the election of directors and significant corporate transactions, such as a merger or other sale of our company or its assets, for the foreseeable future. In addition, this concentrated control will limit your ability to influence corporate matters and, as a result, we may take actions that our stockholders do not view as beneficial.

Mr. Kelly controls approximately 35.8% of the voting power of the Company’s share capital by virtue of his ownership of the Company’s Series A Preferred Stock and Mr. Funk controls approximately 36.6% of the voting power of the Company’s share capital by virtue of his ownership of the Company’s Series A Preferred Stock and his ability to vote an additional 1,000,0000 shares of common stock owned by Rotary Partners LLC. Accordingly, Messrs Funk and Kelly are able to exert a significant degree of influence over our affairs and control over matters requiring shareholder approval, including the election of directors, any amendments to our articles or by-laws and significant corporate transactions. The interests of this concentration of ownership and voting control may not always coincide with the Company’s interests or the interests of other shareholders. For instance, officers, directors, and principal shareholders, acting together, could cause the Company to enter into transactions or agreements that it would not otherwise consider. Similarly, this concentration of ownership and voting control may have the effect of delaying or preventing a change in control of the Company otherwise favored by our other shareholders. This concentration of ownership and voting control could also depress our share price.

We do not intend to pay dividends for the foreseeable future.

We have paid no dividends on our Common Stock to date and it is not anticipated that any dividends will be paid to holders of our Common Stock in the foreseeable future. While our future dividend policy will be based on the operating results and capital needs of our business, it is currently anticipated that any earnings will be retained to finance our future expansion and for the implementation of our business plan. As an investor, you should take note of the fact that a lack of a dividend can further affect the market value of our stock, and could significantly affect the value of any investment.

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

The following management’s discussion and analysis should be read in conjunction with Stratex’s historical financial statements and the related notes. This management’s Discussion and analysis contains forward-looking statements that involve risks and uncertainties, such as statements of our plans, objectives, expectations and intentions. Any statements that are not statements of historical fact are forward-looking statements. When used, the words “believe,” “plan,” “intend,” “anticipate,” “target,” “estimate,” “expect” and the like, and/or future tense or conditional constructions (“may,” “could,” “should,” etc.), or similar expressions, identify certain of these forward-looking statements. These forward-looking statements are subject to risks and uncertainties that could cause actual results or events to differ materially from those expressed or implied by the forward-looking statements in this Current Report on Form 8-K. Our actual results and the timing of events could differ materially from those anticipated in these forward-looking statements as a result of several factors. We do not undertake any obligation to update forward-looking statements to reflect events or circumstances occurring after the date of this Current Report.

As the result of the Transactions and the change in our business and operations to an oil and gas company, a discussion of the past financial results of Pubco is not pertinent, and the financial results of Stratex, the accounting acquirer, are considered our financial results on a historical and going-forward basis.

Overview

We are an independent energy company focused on the exploration, acquisition and production of crude oil in the North Dakota, Montana, Colorado, Kansas and Nebraska. Our oil and natural gas operations are primarily concentrated in the Williston Basin of North Dakota and Montana and Denver-Julesburg Basin in Colorado. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects, and evaluate those prospects using subsurface geology, geophysical data and exploratory drilling. Using this strategy, we intend to develop an oil portfolio of proven reserves, as well as developmental and exploratory drilling opportunities.

Our core operating areas are the Williston Basin in North Dakota and Montana and the Denver-Julesburg Basin in Colorado. In the Williston Basin, we focus on oil production from multiple zones including the Bakken Shale, and Three Forks Sanish Formations. In the Denver-Julesburg Basin we focus on the Niobrara Formations.

We typically hold minority interest leasehold acreage in our core operating areas. In these minority working interest leaseholds, we have historically participated, and expect to continue to participate, on a non-operated basis in the drilling and production of acreage operated by independent oil and gas operating companies.

By participating in drilling activities with larger operators, we seek to leverage their resources and expertise to efficiently gain exposure to potential new oil and gas production and proven reserves. In the Permian Basin, some of these operators have historically drilled and operated traditional, vertical wells. In the Williston Basin, we have participated in wells where the operators have historically drilled unconventional, horizontal wells into prospective oil and gas bearing shale formations.

As of July 6, 2012, we have approximately 22,337 net acres in Sheridan, Montana, Williams, Divide, Mountrail, and Stark, North Dakota, Sioux, Nebraska, and Weld, Colorado. We do not own the majority working interest in this acreage, nor do we have any ability to influence the potential development of this acreage within the terms of the lease. These working interests grant us the right, as the lessee of the property, to explore for, develop and produce oil, natural gas and other minerals, while bearing our portion of related exploration, development and operating costs.

Commodity Prices

Our results of operations are heavily influenced by commodity prices. Factors that may impact future commodity prices, including the price of oil and natural gas, include:

●

developments generally impacting the Middle East, including Iraq, Iran, Libya and Egypt;

●

the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas;

●

the overall global demand for oil;

●

overall North American natural gas supply and demand fundamentals;

●

the impact of the decline of the United States economy;

●

weather conditions; and

●

liquefied natural gas deliveries to the United States.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we will evaluate the benefits of hedging a portion of our commodity price risk to mitigate the impact of price volatility on our business.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. In general, average oil and natural gas prices were substantially higher during the comparable periods of 2011 measured against 2010. The following table sets forth the average New York Mercantile Exchange (NYMEX) oil and natural gas prices for the years ended December 31, 2011 and 2010, as well as the high and low NYMEX price for the same periods:

	Years Ended December 31,
	2011		2010
Average NYMEX prices:
Oil (Bbl)	$	95.03	$	79.48
Natural gas (MMBtu)	$	3.99	$	4.37
High / Low NYMEX prices:
Oil(Bbl):
High	$	113.93	$	91.48
Low	$	79.20	$	64.78
Natural Gas (MMBtu):
High	$	4.92	$	7.51
Low	$	2.84	$	3.18

Results of Operations for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011:

Revenues:

We generated revenues of $237,419 for the three months ended June 30, 2012 and $0 for the three months ended June 30, 2011. The increase in revenue reflects an increase in sales volumes as a result of additional producing wells during the three months ended June 30, 2012. The Company was newly incepted and was acquiring properties during 2011.

Operating Expenses:

●	Production expense was $52,941 for the three months ended June 30, 2012 and $0 for the three months ended June 30, 2011. The increase in expense reflects an increase in the properties and producing wells during the three months ended June 30, 2012. The Company was newly incepted and was acquiring properties during 2011.

●	General and administrative expense was $694,362 for the three months ended June 30, 2012 and $222,253 for the three months ended June 30, 2011. The increase in expense is primarily attributable to an increase in professional fees for the Company’s merger, an increase in salaries and payroll related expenses, and an increase in stock based compensation to employees. In addition, the company engaged key consultants to assist in the oil and gas efforts.

●	Depreciation, depletion and amortization expense was $100,459 for the three months ended June 30, 2012 and $0 for the three months ended June 30, 2011. The increase in expense reflects an increase in the properties and producing wells during the three months ended June 30, 2012. The Company was newly incepted and was acquiring properties during 2011.

Other Income and (Expense):

Other income (expense) was $(86,103) for the three months ended June 30, 2012 and $(16,703) for the three months ended June 30, 2011. Other income (expense) consisted of interest expense on the notes and convertible notes entered into during the period January 25, 2011 (Date of Inception) through June 30, 2012. In addition, the company accretes debt discount associated with the derivative liability through interest expense and recognized a decrease in fair market value of the derivative liability during the three months ended June 30, 2012.

Results of Operations for the six months ended June 30, 2012 as compared to the period January 25, 2011 (Date of Inception) to June 30, 2011:

Revenues:

We generated revenues of $457,630 for the six months ended June 30, 2012 and $0 for the period January 25, 2011 (Date of Inception) to June 30, 2011. The increase in revenue reflects an increase in sales volumes as a result of additional producing wells during the six months ended June 30, 2012. The Company was newly incepted and was acquiring properties during 2011.

Operating Expenses:

●

Production expense was $121,245 for the six months ended June 30, 2012 and $0 for the period January 25, 2011 (Date of Inception) to June 30, 2011. The increase in expense reflects an increase in the properties and producing wells during the six months ended June 30, 2012. The Company was newly incepted and was acquiring properties during 2011.

●

General and administrative expense was $975,945 for the six months ended June 30, 2012 and $251,613 for the period January 25, 2011 (Date of Inception) to June 30, 2011 . The increase in expense is primarily attributable to an increase in professional fees for the Company’s merger, an increase in salaries and payroll related expenses, and an increase in stock based compensation to employees. In addition, the company engaged key consultants to assist in the oil and gas efforts.

●

Depreciation, depletion and amortization expense was $167,662 for the six months ended June 30, 2012 and $0 for the period January 25, 2011 (Date of Inception) to June 30, 2011 . The increase in expense reflects an increase in the properties and producing wells during the six months ended June 30, 2012. The Company was newly incepted and was acquiring properties during 2011.

Other Income and (Expense):

Other income (expense) was $(310,682) for the six months ended June 30, 2012 and $(16,703) for the period January 25, 2011 (Date of Inception) to June 30, 2011. Other income (expense) consisted of interest expense on the notes and convertible notes entered into during the period January 25, 2011 (Date of Inception) through June 30, 2012. In addition, the company accretes debt discount associated with the derivative liability through interest expense and recognized a decrease in fair market value of the derivative liability during the six months ended June 30, 2012.

Results of Operations for the three months ended March 31, 2012 as compared to the Period January 25, 2011 (Date of Inception) to March 31, 2011:

Revenues:

We generated revenues of $220,211 for the three months ended March 31, 2012 and $0 for the period January 25, 2011 (Date of Inception) to March 31, 2011. The increase in revenue reflects an increase in sales volumes as a result of additional producing wells during the three months ended March 31, 2012. The Company was newly incepted and was acquiring properties during 2011.

Operating Expenses:

●

Production expense was $68,304 for the three months ended March 31, 2012 and $0 for the period January 25, 2011 (Date of Inception) to March 31, 2011. The increase in expense reflects an increase in the properties and producing wells during the three months ended March 31, 2012. The Company was newly incepted and was acquiring properties during 2011.

●

General and administrative expense was $281,583 for the three months ended March 31, 2012 and $29,360 for the period January 25, 2011 (Date of Inception) to March 31, 2011. The increase in expense is primarily attributable to an increase in professional fees for the Company’s planned share exchange with a public company. In addition, the company engaged key consultants to assist in the oil and gas efforts.

●

Depreciation, depletion and amortization expense was $67,203 for the three months ended March 31, 2012 and $0 for the period January 25, 2011 (Date of Inception) to March 31, 2011. The increase in expense reflects an increase in the properties and producing wells during the three months ended March 31, 2012. The Company was newly incepted and was acquiring properties during 2011.

Other Income and Expense:

Other income/expense was $(224,579) for the three months ended March 31, 2012 and $(2,601) for the period January 25, 2011 (Date of Inception) to March 31, 2011. Other income (expense) consisted of interest expense on the notes and convertible notes entered into during the period January 25, 2011 (Date of Inception) through March 31, 2012. In addition, the company accretes debt discount associated with the derivative liability through interest expense.

Results of Operations for the Period January 25, 2011(Date of Inception) to December 31, 2011:

Revenues:

We generated revenues of $240,122 for the period January 25, 2011 (Date of Inception) to December 31, 2011 from oil and gas efforts. The Company was newly incepted and was acquiring properties during 2011.

Operating Expenses:

●	Production expense was $101,265 for the period January 25, 2011 (Date of Inception) to December 31, 2011. The Company was newly incepted and was acquiring properties during 2011.

●

General and administrative expense was $828,229 for the period January 25, 2011 (Date of Inception) to December 31, 2011. The expense is primarily attributable to in professional fees for the Company’s planned share exchange with a public company. In addition, the company engaged key consultants to assist in the oil and gas efforts.

●	Depreciation, depletion and amortization expense was $110,793 for the period January 25, 2011 (Date of Inception) to December 31, 2011. The Company was newly incepted and was acquiring properties during 2011.

Other Income and Expense:

Other income/expense was $(184,394) for the period January 25, 2011 (Date of Inception) to December 31, 2011. Other income (expense) consisted of interest expense on the notes and convertible notes entered into during the period January 25, 2011 (Date of Inception) through December 31, 2011. In addition, the company accretes debt discount associated with the derivative liability through interest expense.

Liquidity and Capital Resources:

We have incurred net operating losses and operating cash flow deficits since inception, continuing through the first two quarters of 2012. We are in the early stages of acquisition and development of oil and gas leaseholds and properties, and we have been funded primarily by a combination of equity issuances and debt, and to a lesser extent by operating cash flows, to execute on our business plan of acquiring working interests in oil and gas properties and for working capital for production. At June 30, 2012, we had cash and cash equivalents totaling approximately $431,000.

Our ability to obtain financing may be impaired by many factors outside of our control, including the capital markets (both generally and in the crude oil and natural gas industry in particular), our limited operating history, the location of our crude oil and natural gas properties and prices of crude oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and other factors. Further, if crude oil or natural gas prices on the commodities markets decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital.

Any new debt or equity financing arrangements may not be available to us, or may be available only on unfavorable terms. Additionally, these alternatives could be highly dilutive to our existing stockholders, and may not provide us with sufficient funds to meet our long-term capital requirements. We have and may continue to incur substantial costs in the future in connection with raising capital to fund our business, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, which may adversely impact our financial condition. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we will be required to reduce operating costs, which could jeopardize our future strategic initiatives and business plans, and we may be required to sell some or all of our properties (which could be on unfavorable terms), seek joint ventures with one or more strategic partners, strategic acquisitions and other strategic alternatives, cease our operations, sell or merge our business, or file a petition for bankruptcy.

Our financial statements for the six months ended June 30, 2012 were prepared assuming we would continue as a going concern, which contemplates that we will continue in operation for the foreseeable future and will be able to realize assets and settle liabilities and commitments in the normal course of business. These financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that could result should we be unable to continue as a going concern.

Cash from Operating Activities

Cash used in operating activities was $(129,897) for the six months ended June 30, 2012, as compared to cash used in operating activities of $(272,876) during the period January 25, 2011 (Date of Inception) to June 30, 2011. The decrease in cash used in operating activities is due to the Company burning off inventory and an increase in accrued liabilities.

Cash from Investing Activities

Cash used for investing activities for the six months ended June 30, 2012 was $(553,134) as compared to $(685,618) during the period January 25, 2011 (Date of Inception) to June 30, 2011. The decrease is due to a decrease in capital acquisition during 2012 as compared to the comparable period ended 2011.

Cash from Financing Activities

Total net cash provided by financing activities was $528,335 for the six months ended June 30, 2012, from various debt and equity offerings. Total net cash provided by financing activities during the period January 25, 2011 (Date of Inception) to June 30, 2011 was $1,789,395 from various debt and equity offerings. For more details about these debt and equity financings, see Notes to the Consolidated Financial Statements for the year ended December 31, 2011 and the six months ended June 30, 2012.

Planned Capital Expenditures

Dependent on our ability to obtain sufficient financing, development plans for 2012 include identifying and acquiring additional properties and leases in different operators and regions.

The Company incurred approximately $60,000 in development costs on the well during July and August 2012. The Company expects to incur maintenance costs of approximately $7,000 to $9,000 per month for the next twelve months to maintain the asset.

Critical Accounting Policies and Estimates:

Our discussion of our financial condition and results of operations is based on the information reported in our financial statements. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are described in Note 2 –Summary of Significant Accounting Policies to our consolidated financial statements and notes. We have outlined below certain of these policies that have particular importance to the reporting of our financial condition and results of operations and that require the application of significant judgment by our management.

Key Definitions

Proved reserves, as defined by the SEC, are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Valuations include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Prices do not include the effect of derivative instruments, if any, entered into by us.

Proved developed reserves are those reserves expected to be recovered through existing equipment and operating methods. Additional oil and gas volumes expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery would be included as proved developed reserves only after testing of a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves are those reserves that are expected to be recovered from new wells on non-drilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on non-drilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other non-drilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

Estimation of Reserves

Volumes of reserves are estimates that, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data as well as production performance data. There are numerous uncertainties in estimating crude oil and natural gas reserve quantities, projecting future production rates and projecting the timing of future development expenditures. Natural gas and oil reserve engineering must be recognized as a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. Estimates of independent engineers that we use may differ from those of other engineers. The accuracy of any reserve estimate is a function of the quantity and quality of available data and of engineering and geological interpretation and judgment. Accordingly, future estimates are subject to change as additional information becomes available.

The most critical estimate we make is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depletion, depreciation and amortization of oil and gas properties and the estimate of any impairment of our oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the annual year end disclosure of the related standardized measure of discounted future net cash flows .

Revenues from the sale of oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. 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. We recognize a receivable or liability only to the extent that we have an imbalance on a specific property greater than our share of the expected remaining proved reserves. For oil sales, this occurs when the customer's truck takes delivery of oil from the operators’ storage tanks

Successful Efforts Accounting

We utilize the successful efforts method to account for our natural gas and oil operations. Under this method, all costs associated with natural gas and oil lease acquisitions, successful exploratory wells and all development wells are capitalized. Development costs of producing properties are amortized on a units-of-production basis over the remaining life of proved developed producing reserves, and leasehold costs associated with producing properties are amortized on a units-of-production basis over the remaining life of all proved reserves associated with the leases on which producing properties are drilled. Unproved leasehold costs are capitalized pending the results of exploration efforts. Exploration costs, including geological and geophysical expenses, exploratory dry holes and delay rentals, are expensed when incurred.

Impairment of Properties

We review our proved properties for potential impairment at the field level when management determines that events or circumstances indicate that the recorded carrying value of any of the properties may not be recoverable. Such events include a projection of future natural gas and oil reserves that will be produced from a well, the timing of this future production, future costs to produce the natural gas and oil, and future inflation levels. If the carrying amount of an asset exceeds the sum of the discounted estimated future net cash flows, we recognize impairment expense equal to the difference between the carrying value and the fair market value of the asset, which is estimated to be the expected discounted value of future net cash flows from reserves, without the application of any estimate of risk. We cannot predict the amount of impairment charges that may be recorded in the future. Unproved leasehold costs are reviewed periodically and impairment is recognized to the extent, if any, that the cost of the property has been impaired. We follow the Accounting Standards Codification ASC 360 Property, Plant, and Equipment, for these evaluations. Unamortized capital costs are reduced to fair value if the undiscounted future net cash flows from our interest in the property’s estimated proved reserves are less than the asset’s net book value.

Proved Reserves

Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States of America and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and amortization expense and the impairment. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves. We engage independent reserve engineers to estimate our proved reserves.

Share-Based Compensation

Compensation expense has been recorded for grants of restricted common stock and options based on the fair value of the common stock on the measurement date. We estimate the fair value of each stock option awarded at the grant date by using the Black-Scholes option pricing model. FASB ASC Topic No. 718-10 establishes standards for transactions in which an entity obtains employee services in share-based payment transactions. The guidance requires that the fair value of such equity instruments be recognized as expense in the historical financial statements as services are performed. Standards of accounting for transactions in which an entity exchanges its equity instruments for goods and services by a consultant or contractor are further governed by FASB ASC Topic No. 505-50 by which the grant is measured at the fair value of the stock exchanged and the associated expense is recorded according to the category of the good or service rendered.

Derivative Valuation

We estimate the fair value of financial assets and liabilities based on a three-level valuation hierarchy for disclosures of fair value measurement and enhance disclosure requirements for fair value measures.

The three levels are defined as follows:

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

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

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

All derivative instruments are recorded on the balance sheet at their fair value. Changes in the fair value of each derivative are recorded each period in current period earnings.

New Accounting Pronouncements

We do not expect the adoption of any recently issued accounting pronouncements to have a significant impact on our results of operations, financial position or cash flows.

Leasehold Holdings

As of July 6, 2012 we held working interests in approximately 22,337 net acres in the Williston Basin of North Dakota and Montana and Denver-Julesburg Basin in Colorado. We also hold mineral lease rights in and well interest in Nebraska and Kansas. These working interests grant us the right, as the lessee of the property, to explore for, develop and produce oil, natural gas and other minerals, while also bearing any related exploration, development, and operating costs.

The following represent Stratex’s mineral leases holdings as of July 6, 2012

●	22,000 gross and 13,900 net mineral acres in Golden Valley, North Dakota.

●	7,274 gross and 1,661 net mineral acres located in Sheridan County, Montana.

●	2,080 gross and 114 net mineral acres located in Acres located in Lane and Ellis Counties, Kansas with 7 operating wells.

●	60,000 gross and 6,000 net mineral acres located in Sioux Nebraska.

●	355 gross and 120 net mineral acres located in Wattenberg Field in the Denver-Julesberg Niobrara Formation, Colorado.

●	640 gross and 260 net mineral acres operating well in Roosevelt County, Montana with one operating well.

●	640 gross and 121 net mineral acres in Stark County, North Dakota.

●	640 gross and 120 net mineral acres in Mountrail County, North Dakota.

●	640 gross and 32 net mineral acres in Williams County, North Dakota.

●	640 gross and 4 net mineral acres in Divide County, North Dakota.

●	709 gross and 5 net mineral acres in Williams County, North Dakota.

SECURITY OWNERSHIP OF CERTAIN STOCKHOLDERS AND MANAGEMENT

The following tables set forth certain information regarding the beneficial ownership of our Common Stock and Series A Preferred Stock as of February 11, 2013 by (i) each person who, to our knowledge, owns more than 5% of the Common Stock; (ii) each of our directors and executive officers; and (iii) all of our executive officers and directors as a group. Unless otherwise indicated in the footnotes to the following tables, each person named in the table has sole voting and investment power and that person’s address is c/o Stratex Holdings, Inc., 30 Echo Lake Road, Watertown, CT 06795. Shares of Common Stock subject to options or warrants currently exercisable or exercisable within 60 days of February 11, 2013 are deemed outstanding for computing the share ownership and percentage of the person holding such options and warrants, but are not deemed outstanding for computing the percentage of any other person.

Name and address of Beneficial Owner	Common Stock par value $.0001 per share		Percent of Common Stock Outstanding(2)			Series A Preferred Stock par value $.0001 per shares		Percent of Series A Preferred Stock Outstanding
Rotary Partners LLC (1)		1,000,000		2.5	%		50		50	%
Timothy Kelly		0	NA				50		50	%
Avi Dan 245 E 54th St. New York, NY 10022		4,750,000		12.03	%	NA		NA
Kenneth D. Savino 61 Scarsborough St. Hartford, CT 06105		2,269,945		5.74	%	NA		NA

(1)	Stephen Funk, our CEO and one of our directors, has voting and dispositive control of the common stock held by Rotary Partners LLC.
(2)	Based on 39,482,550 shares of common stock issued and outstanding

Changes in Control

We are not aware of any or a party to arrangements, including any pledge by any person of our securities, the operation of which may at a subsequent date result in a change of control.

DIRECTORS AND EXECUTIVE OFFICERS

The following persons are our executive officers, non-executive officers and directors and hold the positions set forth opposite their name.

Name	Age		Position(s)
Stephen Funk		49	Chairman of the Board, Chief Executive Officer

Timothy Kelly		43	President, Chief Operating Officer, Secretary and Director

Stephen Funk, Chief Executive Officer and Chairman of the Board

Stephen Funk has served as our Chief Executive Officer since January 2011 and devotes 100% of his professional time to our business. From March 2008 to December 2010, through Alta Investments, LLC, Mr. Funk was a managing member of Cherokee Enterprises LLC, a construction dewatering company to the heavy construction industry whose main services involved drilling water wells and pumping water to lower water tables near major construction projects. From 1999 to March 2008, Mr. Funk operated Alta Investments LLC.

Mr. Funk graduated from Marist College in 1984 with a B.S. in Business Administration, Finance.

Relating to Mr. Funks employment with Wellesley Services LLC in 1999: On March 31, 2006, Mr. Funk entered into a Consent Order with the New Jersey Bureau of Securities for alleged violations of the New Jersey Uniform Securities Law, pursuant to which he agreed to permanent injunctive relief from directly or indirectly violating the NJ Securities Law.

Timothy Kelly, President & Chief Operating Officer, Secretary and Director

Tim Kelly has served as our President and Chief Operating Officer since January 2011 and devotes 100% of his professional time to our business. From May 2009 to January 2011, Mr. Kelly served as General Partner at Lynden Capital where he directed investments in small cap public and private companies. From January 2003 to May 2009, Mr. Kelly served as a Registered Representative at Thomas Group Capital. From March 2001 to October 2002, Mr. Kelly served as a Registered Representative at Donaldson Lufkin & Jenrette Securities Corporation/CS First Boston.

Mr. Kelly graduated from Providence College in 1990 with a B.S. in Business Administration, Marketing.

On January 9, 2012, pursuant to Article VI, Section 3 of the Financial Industry Regulatory Authority (FINRA) bylaws and FINRA Rule 9554, Mr. Kelly was suspended for failure to comply with an arbitration award in the amount of approximately $95,000 and to satisfactorily respond to a FINRA request to provide information concerning the status of compliance. The award against Mr. Kelly resulted from customer claims in arbitration that he violated securities rules and regulations.

Family Relationships

None

Involvement in Certain Legal Proceedings

Except for the disclosure in Mr. Funk’s and Mr. Kelly’s biography’s, during the past ten years, none of our directors, executive officers, promoters, control persons, or nominees has:

–	been convicted in a criminal proceeding or been subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);
–	had any bankruptcy petition filed by or against the business or property of the person, or of any partnership, corporation or business association of which he was a general partner or executive officer, either at the time of the bankruptcy filing or within two years prior to that time;
–	been subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction or federal or state authority, permanently or temporarily enjoining, barring, suspending or otherwise limiting, his involvement in any type of business, securities, futures, commodities, investment, banking, savings and loan, or insurance activities, or to be associated with persons engaged in any such activity;
–	been found by a court of competent jurisdiction in a civil action or by the SEC or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated;
–	been 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 (not including any settlement of a civil proceeding among private litigants), relating to an alleged violation of any federal or state securities or commodities law or regulation, 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 any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or
–	been 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.

Consultants

David Briones, Interim Financial Reporting Consultant

Mr. Briones performs outsourced CFO functions including, preparing annual and quarterly financial statements and accompanying notes in accordance with Generally Accepted Accounting Principles (GAAP) in coordination with our independent auditor and provides consultation in the accounting of complex financial transactions, such as the valuation, recognition, reporting and disclosure of all equity transactions, such as the valuation, recognition, reporting and disclosure of all equity transactions and complex financial instruments.

Mr. Briones served as the chief financial officer of Clear-Lite Holdings, Inc. from August 3, 2009 to March 21, 2011 and currently serves as Chief Financial Officer for NXT Nutritional Holdings, Inc., a publicly traded company on the Over the Counter Bulletin Board.

Mr. Briones has a Bachelor of Science in Accounting from Fairfield University, Fairfield, Connecticut.

William Kazmann, LaRoache Petroleum, Ltd.

The technical person primarily responsible for overseeing the preparation of reserves estimates herein is William M. Kazmann. Mr. Kazmann is a Professional Engineer licensed in the State of Texas who has thirty seven years of engineering experience in the oil and gas industry. Mr. Kazmann earned Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of Texas at Austin and has prepared reserves estimates for his employers and his own companies throughout his career. He has prepared and overseen preparation of reports for public filings for LPC for the past fifteen years.

Samuel Epstein, Certified Petroleum Geologist

Mr. Epstein heads Geoval Consulting a petroleum geological consulting group. Mr. Epstein’s primary responsibilities will involve the analysis of geochemical, structural, stratigraphic, production maps with respect to existing and potential land holdings along with providing written analysis of the resulting data. Mr. Epstein is a certified petroleum geologist and has over 32 years of experience with integrated complex petroleum geochemical, sedimentological, and structural systems analysis.

Mr. Epstein holds a Bachelors of Science Degree (1977) from Brooklyn College, and a Master of Science (1977) from Rensselaer Polytechnic Institute. Mr. Epstein has over 25 publications in referenced scientific journals concerning petroleum exploration and production, and the effects of global warming on sea level changes.

EXECUTIVE COMPENSATION

The following table sets forth information regarding each element of compensation that we paid or awarded to our named executive officers for fiscal 2011.

Name and Principal Position	Year	Salary($)		Bonus		Stock Awards ($) (1)		Option Awards ($) (2)		All Other Compensation		Total($)
Stephen Funk	2011		64,888		0		0		0		0		64,888
Chief Executive Officer

Timothy Kelly	2011		67,822		0		0		0		0		67,822
President, COO

Employment Agreements

Each of the named executive officers executed employment agreements on with Stratex, which we adopted.

Mr. Funk’s employment agreement is for a period of 5 years, after which the agreement is renewable for 1 year periods, unless the Company or Mr. Funk gives 6 months notice of the intention to terminate the agreement. Mr. Funk receives a salary of $250,000 per year with annual increases of 10% per year. Mr. Funk will also receive an annual cash bonus in an amount to be determined by the Board of Directors.

Mr. Funk has been granted options to acquire 3,000,000 shares of restricted stock of the Company, which shall be subject to, and vest over a period of three (3) years. Additionally, Mr. Funk was issued 50 shares of Stratex Preferred Stock. The shares of Preferred Stock have no liquidation or dividend preference and entitle Mr. Funk to fifty million (50,000,000) votes on all matters submitted to a vote of the shareholders of the Company.

The Company agrees to promptly reimburse Mr. Funk for all reasonable and necessary business expenses, including without limitation, telephone and facsimile charges incurred by him on behalf of the Company. In addition the Company agrees to provide Mr. Funk with a monthly automobile allowance of $750.

Mr. Kelly’s employment agreement is for a period of 5 years, after which the agreement is renewable for 1 year periods, unless the Company or Mr. Kelly gives 6 months notice of the intention to terminate the agreement. Mr. Kelly receives a salary of $250,000 per year with annual increases of 10% per year. Mr. Kelly will also receive an annual cash bonus in an amount to be determined by the Board of Directors.

Mr. Kelly has been granted options to acquire 3,000,000 shares of restricted stock of the Company, which shall be subject to, and vest over a period of three (3) years. Additionally, Mr. Kelly was issued 50 shares of Stratex Preferred Stock. The shares of Preferred Stock have no liquidation or dividend preference and entitle Mr. Kelly to fifty million (50,000,000) votes on all matters submitted to a vote of the shareholders of the Company.

The Company agrees to promptly reimburse Mr. Kelly for all reasonable and necessary business expenses, including without limitation, telephone and facsimile charges incurred by him on behalf of the Company. In addition the Company agrees to provide Mr. Funk with a monthly automobile allowance of $750.

Outstanding Equity Awards at Fiscal Year End

The following table summarizes the equity awards issued and outstanding as of the date hereof.

	No. of Securities Underlying Unexercised Options (#) Exercisable		No. of Securities Underlying Unexercised Options (#) Unexercisable		Option Exercise Price		Option Expiration Date		Number of shares or Units of stock that have not vested(#)		Market Value of shares or Units of stock that have not vested($)
Stephen Funk		1,500,000		1,500,000	$	0.25		0		1,500,000	$	0
Timothy Kelly		1,500,000		1,500,000	$	0.25		0		1,500,000		0

Stratex Plan

Our Board of Directors adopted and assumed the Stratex Plan in July 2012. A total of 12,000,000 shares of our common stock are reserved for issuance under the Stratex Plan to our executive officers, directors, consultants and employees. If an incentive award granted under the Stratex Plan expires, terminates, is unexercised or is forfeited, or if any shares are surrendered to us in connection with an incentive award, the shares subject to such award and the surrendered shares will not become available for further awards under the Stratex Plan. Additionally, shares used to pay the tax or exercise price of an award will become available for future grant or sale under the Stratex Plan. To the extent an award under the Stratex Plan is paid out in cash rather than shares, the cash payment will not result in reducing the number of shares available for issuance under the Stratex Plan.

The maximum number of shares that may be issued upon the exercise of the Incentive Stock Options will equal the aggregate Share number stated above, plus, to the extent allowable under section 422 of the Code, and any shares that become available for issuance under the Plan.

The Company during the term of this Plan will at all times reserve and keep available such number of shares as will be sufficient to satisfy the requirements of the Plan

The number and class of shares of our Common Stock subject to the Stratex Plan, the number and class of shares subject to any numerical limit in the Stratex Plan, and the number, price and class of shares subject to awards will be adjusted in the event of any change in our outstanding Common Stock by reason of any stock dividend, spin-off, split-up, stock split, reverse stock split, recapitalization, reclassification, merger, consolidation, liquidation, business combination or exchange of shares or similar transaction.

Administration

It is expected that the compensation committee of the Board, or the Board in the absence of such a committee, will administer the Stratex Plan. Subject to the terms of the 2012 Plan, the compensation committee would have complete authority and discretion to determine the terms of awards under the Stratex Plan.

Eligibility

Non-statutory stock options and other such cash or stock awards as the Administrator determine may be granted to Service Providers. Incentive stock Options may be granted only to employees.

Stock Options. Stock options entitle the participant, upon exercise, to purchase a specified number of shares of common stock at a specified price for a specified period of time. Each option will be designated in the Award Agreement as either an Incentive Stock Option or a nonstatutory Stock Option. However, notwithstanding such designation to the extent that the Fair Market Value of the shares are exercisable for the first time by the participant during any calendar year exceeds $100,000 then the Options will be treated as Nonstatutory Stock Options. Incentive Stock Options will be taken into account in the order which they were granted. The Fair Market Value of the shares will be determined at the time they are granted.

The administrator will determine the term of each option in its sole discretion however the term will be no more than 10 years from the date of the Grant. Moreover, in the case that an Incentive Stock Option is granted to a Participant who owns stock representing more than 10% of the total combined voting power of all classes of stock of the Company or Parent then the term of the Incentive Stock Option will be a maximum of 5 years from the date of the grant.

The Administrator may grant incentive and/or nonstatutory stock options under the Stratex Plan. The exercise price for each stock option shall be determined by the Administrator but shall not be less than 100% of the fair market value of the common stock on the date of grant. The “fair market value” means, if the stock is listed on any established stock exchange or national market system, the closing sales price of the stock, or, if the common stock is regularly quoted by a recognized securities dealer, but the selling prices are not reported, the mean between the high bid and low asked prices for the common stock on the day of determination, or in the absence of an established market for the stock, or if the stock is not regularly quoted or does not have sufficient trades or bid prices which would reflect the stock’s actual fair market value, the fair market value of the common stock will be determined in good faith by the Administrator upon the advice of a qualified valuation expert.

Any stock options granted in the form of an incentive stock option will be intended to comply with the requirements of Section 422 of the Code. Only options granted to employees qualify for incentive stock option treatment.

Each stock option shall expire at such time as the Administrator shall determine at the time of grant. No stock option shall be exercisable later than the tenth anniversary of its grant. A stock option may be exercised in whole or in installments. A stock option may not be exercisable for a fraction of a share. Shares of common stock purchased upon the exercise of a stock option must be paid for in full at the time of exercise in cash or such other consideration determined by the Administrator.

All awards made under the 2012 Plan may be subject to vesting and other contingencies as determined by the Administrator and will be evidenced by agreements approved by the Administrator which set forth the terms and conditions of each award.

Duration, Amendment, and Termination

Unless sooner terminated by the Board, the Stratex Plan will terminate ten years after its adoption. The Board may amend, alter, suspend or terminate the Stratex Plan at any time or from time to time without stockholder approval or ratification, unless necessary and desirable to comply with applicable law. However, before an amendment may be made that would adversely affect a participant who has already been granted an award, the participant’s consent must be obtained.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Transactions with Pubco Shareholders

Pubco’s common stock was forward-split on a 3.5 for 1 basis, with a record date of May 15, 2012 and an effective date of May 31, 2012. As a result of this stock split, there were approximately 6,110,000 shares of the Pubco’s common stock issued and outstanding before taking into account the issuance of shares of Common Stock in the Merger and after giving pro forma effect to the Split-Off, as discussed below.

Upon the closing of the Merger, Pubco transferred all of its operating assets and liabilities to PSOS and split-off PSOS through in consideration for the cancellation of a shareholder loan in the amount of $79,687 owed to the Split-Off Shareholder.

DESCRIPTION OF CAPITAL STOCK

Authorized Capital Stock

As of the date hereof, our authorized capital stock consisted of 750,000,000 shares of Common Stock, no par value per share and 10,000,000 shares of preferred stock no par value per share.

Issued and Outstanding Capital Stock

After giving effect to the Transactions, the Common Stock sold in the Offering and the options assumed under the Stratex Plan, we have the following issued and outstanding securities:

■

39,482,550 shares of Common Stock;

■

100 shares of Series A preferred stock

■

Options to purchase 3,000,000 shares of Common Stock granted under the Stratex Plan;

■

Warrants to purchase 675,000 shares of Common Stock at a price of $0.70 per share held by Stratex warrant holders; and

■

Stratex Notes in the aggregate principal amount of $250,000

Description of Common Stock

Voting: Holders of our Common Stock are entitled to one vote for each share on all matters submitted to a stockholder vote, except matters that relate only to a series of our preferred stock. Holders of Common Stock do not have cumulative voting rights.

In general, (i) stockholder action (except for bylaw amendments, which requires a majority of shares entitled to vote, and election of directors, which requires a plurality vote) is based on the affirmative vote of a majority of the votes cast and (ii) broker non-votes and abstentions are considered for purposes of establishing a quorum but are not considered as votes cast for or against a proposal or director nominee. Directors are elected by a plurality of the voting power of the shares present in person or represented by proxy at the meeting and entitled to vote on the election of directors. A vote by the holders of a majority of our outstanding shares is required to effectuate certain fundamental corporate changes such as liquidation, merger or an amendment to our certificate of incorporation.

Stockholders may not take action by written consent unless the taking of such action by written consent is approved in advance by resolution of our board of directors.

Dividends: Subject to limitations under Colorado law and preferences that may apply to any then-outstanding shares of preferred stock, holders of Common Stock are entitled to share in all dividends that the board of directors, in its discretion, declares from legally available funds.

We have never declared or paid any cash dividends on our Common Stock. We currently intend to retain future earnings, if any, to finance the expansion of our business. As a result, we do not anticipate paying any cash dividends in the foreseeable future.

Liquidation: In the event of a liquidation, dissolution or winding up, each outstanding share entitles its holder to participate pro rata in all assets that remain after payment of liabilities and after providing for each class of stock, if any, having preference over the Common Stock, subject to the liquidation preference of any then outstanding shares of preferred stock.

Miscellaneous: Holders of our Common Stock have no pre-emptive rights, no conversion rights and there are no redemption provisions applicable to our Common Stock. All outstanding shares of Common Stock are fully paid and non-assessable.

Preferred Stock

Our Certificate of Incorporation empowers our board of directors, without further action by our stockholders, to issue up to 10,000,000 shares of preferred stock from time to time in one or more series. Our board of directors is authorized to fix and determine the designations, powers, preferences and rights, and the qualifications, limitations or restrictions, of the preferred stock, including dividend rights, dividend rates, conversion rights, voting rights, rights and terms of redemption, the redemption price or prices and liquidation preferences, any or all of which may be greater than the rights of the common stock.

Currently there are 100 shares of Series A preferred stock issued and outstanding. Each share of Series A Preferred Stock entitles the holder to one million (1,000,000) times that number of votes on all matter submitted to the stockholders that each share of common stock is entitled to vote at each meeting of stockholders. The Series A Preferred Stock have no liquidation, conversion or dividend rights.

Stratex Warrants

As of July 6, we issued 7 separate five-year common stock purchase warrant agreements exercisable for up to 1,350,000 shares of common stock at $0.35 (675,000 shares of common stock at $.70 post merger) per shares to accredited investors. The exercise price and number of shares of common stock issuable on exercise of the warrant may be adjusted in certain circumstances including in the event of future issuances of our equity securities at a price less than the exercise price of the warrant, in the event of a stock dividend, or our recapitalization, reorganization, merger or consolidation. The warrants grant piggyback registration rights for the shares issuable upon exercise of the warrant

MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Market Information

Our Common Stock is currently available for trading in the over-the-counter market and is quoted on the OTCQB under the symbol “PWMYD.” As of the Closing Date, there was no bid history for the Common Stock, because the Common Stock has traded minimally.

Trades in our Common Stock may be subject to Rule 15g-9 of the Exchange Act, which imposes requirements on broker/dealers who sell securities subject to the rule to persons other than established customers and accredited investors. For transactions covered by the rule, broker/dealers must make a special suitability determination for purchasers of the securities and receive the purchaser’s written agreement to the transaction before the sale.

The SEC also has rules that regulate broker/dealer practices in connection with transactions in “penny stocks.” Penny stocks generally are equity securities with a price of less than $5.00 (other than securities listed on certain national exchanges, provided that the current price and volume information with respect to transactions in that security is provided by the applicable exchange or system). The penny stock rules require a broker/dealer, before effecting a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document prepared by the SEC that provides information about penny stocks and the nature and level of risks in the penny stock market. The broker/dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker/dealer and its salesperson in the transaction, and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker/dealer and salesperson compensation information, must be given to the customer orally or in writing before effecting the transaction, and must be given to the customer in writing before or with the customer’s confirmation. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for shares of our Common Stock. As a result of these rules, investors may find it difficult to sell their shares.

Holders

As of the date of this filing, there are approximately 161 record holders of 39,482,550 shares of Common Stock. As of the date of this filing, 675,000 shares of Common Stock are issuable upon the exercise of outstanding warrants and options. The shares issued in connection with the Transactions, including the Common Stock issued to the former Stratex stockholders, are “restricted securities,” which may be sold or otherwise transferred only if such shares are first registered under the Securities Act or are exempt from the registration requirements.

LEGAL PROCEEDINGS

From time to time, the Company may be named in claims arising in the ordinary course of business. Currently, no legal proceedings or claims are pending against or involve the Company that, in the opinion of management, could reasonably be expected to have a material adverse effect on our business and financial condition.

RECENT SALES OF UNREGISTERED SECURITIES

Sales by Stratex

On January 26, 2011, in connection with our incorporation, we issued 10,500,000 shares of our common stock to our founders in consideration for services rendered.

From February 22, 2011, to June 6, 2011 we issued promissory notes to certain accredited investors in an aggregate amount of $845,000.

From February 22, 2011 to December 31, 2011, we sold through a private offering 28,195,000 shares of common stock at per share price of $0.007 for a total consideration of $197,365.

From June 13, 2011 to October 31, 2011, we sold through a private offering 15,945,000 shares of common stock at per share price of $0.10 for a total consideration of $1,594,480.

From July 20, 2011 to July 5, 2012, we sold through a private offering 8,962,243 shares of common stock at $0.25 per share for a total consideration of $2,240,561.

On October 19, 2011, we sold a convertible promissory note in the aggregate principal amount of $1,100,000 payable May 17, 2012 and a 5 year common stock purchase warrant exercisable for up to 1,000,000 shares of common stock at $0.35 per shares to an accredited investor. On May 17, 2012, we converted the convertible promissory note to 3,142,857 shares of common stock at $0.35 per share for a total consideration of $1,100,000.

On October 27, 2011, we sold a convertible promissory note in the aggregate principal amount of $60,000 payable October 27, 2012 and a 5 year common stock purchase warrant exercisable for up to 50,000 shares of common stock at $0.35 per shares to an accredited investor.

On November 23, 2011, we sold a convertible promissory note in the aggregate principal amount of $120,000 payable November 23, 2012 and a 5 year common stock purchase warrant exercisable for up to 100,000 shares of common stock at $0.35 per shares to an accredited investor.

On December 28, 2011, we sold a convertible promissory note in the aggregate principal amount of $48,000 payable December 28, 2012 and a 5 year common stock purchase warrant exercisable for up to 40,000 shares of common stock at $0.35 per shares to an accredited investor.

On January 23, 2012, we sold a convertible promissory note in the aggregate principal amount of $36,000 payable January 23, 2013 and a 5 year common stock purchase warrant exercisable for up to 30,000 shares of common stock at $0.35 per shares to an accredited investor

On January 30, 2012, we sold a convertible promissory note in the aggregate principal amount of $36,000 payable January 30, 2013 and a 5 year common stock purchase warrant exercisable for up to 30,000 shares of common stock at $0.35 per shares to an accredited investor.

On November 18, 2011, we sold a 10% promissory note in the amount of $100,000 and a 5 year common stock purchase warrant exercisable for up to 100,000 shares of common at $0.35 per share to an accredited investor. On April 29, 2012, we repaid the promissory note for a total consideration of $103,918.

On April 1, 2012, we issued a total of 100 shares of preferred stock to our Chief Executive Offer and our President in exchange for services rendered.

The transactions described above were exempt from registration under Section 4(2) of the Securities Act and Rule 506 of Regulation D thereunder.

Sales by Pubco

On August 26, 2010, 100,000 shares were issued in connection with the December 2008 merger between Ross Investments Inc. and Poway Muffler and Brake Inc. In July 2012, we issued 1,000,000 shares of our common stock to an accredited investor at a price of $0.01 per share, for aggregate consideration of $10,000. These issuances pursuant to the merger were exempt from registration under Section 4(2) of the Securities Act.

INDEMNIFICATION OF OFFICERS AND DIRECTORS

Our officers and directors are indemnified as provided by the Colorado Revised Statutes Section 7-109-102, our Articles of Incorporation and our bylaws.

Under the Colorado Statutes, director immunity from liability to a company or its shareholders for monetary liabilities applies automatically unless it is specifically limited by a company's articles of incorporation. That is not the case with our articles of incorporation. Excepted from that immunity are actions:

(a) in connection with a proceeding by or in the right of the corporation in which the director was adjudged liable to the corporation; or

(b) in connection with any other proceeding charging that the director derived an improper personal benefit, whether or not involving action in an official capacity, in which proceeding the director was adjudged liable on the basis that the director derived an improper personal benefit.

Our bylaws provide that we will indemnify our directors and officers to the fullest extent not prohibited by Colorado law; provided, however, that we may modify the extent of such indemnification by individual contracts with our directors and officers; and, provided, further, that we shall not be required to indemnify any director or officer in connection with any proceeding (or part thereof) initiated by such person unless:

(a) such indemnification is expressly required to be made by law;

(b) the proceeding was authorized by our shareholders;

(c) such indemnification is provided by us, in our sole discretion, pursuant to the powers vested us under Colorado law; or

(d) such indemnification is required to be made pursuant to the bylaws.

Our bylaws provide that we will advance all expenses incurred to any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he is or was our director or officer, or is or was serving at our request as a director or executive officer of another company, partnership, joint venture, trust or other enterprise, prior to the final disposition of the proceeding, promptly following request. This advanced of expenses is to be made upon receipt of an undertaking by or on behalf of such person to repay said amounts should it be ultimately determined that the person was not entitled to be indemnified under our bylaws or otherwise.

PART F/S

Reference is made to the disclosure set forth under Item 9.01 of this Current Report, which disclosure is incorporated herein by reference.

INDEX TO EXHIBITS

See Item 9.01(c) below, which is incorporated by reference herein.

DESCRIPTION OF EXHIBITS

See Exhibit Index below and the corresponding exhibits, which are incorporated by reference herein.

Item 3.02. Unregistered Sales of Equity Securities.

The disclosure set forth in Item 2.01 to this Current Report is incorporated into this item by reference.

Item 4.01. Changes in Registrant’s Certifying Accountant.

On July 6, 2012, we appointed Mahoney Sabol & Company, LLP as our principal independent registered public accounting firm, and effective July 6, 2012, we dismissed John Kinross-Kennedy as our principal independent registered public accounting firm. The decision to dismiss John Kinross-Kennedy and to appoint Mahoney Sabol & Company, LLP was approved by our board of directors.

John Kinross-Kennedy’s report on our financial statements for either of the two most recent fiscal years ended December 31, 2011 and 2010 did not contain an adverse opinion or disclaimer of opinion, or qualification or modification as to uncertainty, audit scope, or accounting principles, except that such report on our financial statements contained an explanatory paragraph in respect to the substantial doubt about our ability to continue as a going concern.

During our two most recent fiscal years ended December 31, 2011 and 2010 and in the subsequent interim period through the date of dismissal, there were no disagreements, resolved or not, with John Kinross-Kennedy on any matter of accounting principles or practices, financial statement disclosure, or audit scope and procedures, which disagreement(s), if not resolved to the satisfaction of John Kinross-Kennedy, would have caused John Kinross-Kennedy to make reference to the subject matter of the disagreement(s) in connection with its report.

During our two most recent fiscal years ended December 31, 2011 and 2010 and in the subsequent interim period through the date of dismissal, there were no reportable events as described in Item 304(a)(1)(v) of Regulation S-K.

We provided John Kinross-Kennedy with a copy of the disclosure in this Item 4.01 of this Current Report on Form 8-K prior to its filing with the SEC, and requested that it furnish us with a letter addressed to the SEC stating whether it agrees with the statements made in this Item 4.01 of this current report on Form 8-K, and if not, stating the respects with which it does not agree. A copy of the letter provided from John Kinross-Kennedy is filed as an Exhibit 16.1 to this Current Report on Form 8-K.

During our two most recent fiscal years ended December 31, 2011 and 2010 and in the subsequent interim period through the date of appointment, we have not consulted with Mahoney, Sabol & Company, LLP regarding either the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements, nor has Mahoney, Sabol & Company, LLP provided to us a written report or oral advice that Mahoney, Sabol & Company, LLP concluded was an important factor considered by us in reaching a decision as to the accounting, auditing or financial reporting issue. In addition, during such periods, we have not consulted with Mahoney, Sabol & Company, LLP regarding any matter that was either the subject of a disagreement (as defined in Item 304(a)(1)(iv) and the related instructions) or a reportable event (as described in Item 304(a)(1)(v) of Regulation S-K).

Item 5.01. Changes in Control of the Registrant.

As a result of the Offering and the Merger, we experienced a change in control, with the former stockholders of Stratex acquiring control of us. The disclosure set forth in Item 2.01 to this Current Report is incorporated into this item by reference.

Item 5.02. Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

The disclosure set forth in Item 2.01 to this Current Report is incorporated into this item by reference.

Item 5.06. Change in Shell Company Status.

The disclosure set forth in Item 2.01 to this Current Report is incorporated into this item by reference. As a result of the completion of the Merger, we believe that we are no longer a shell company, as defined in Rule 405 of the Securities Act and Rule 12b-2 of the Exchange Act.

Item 9.01. Financial Statements and Exhibits.

(a) Financial Statements of business acquired

In accordance with Item 9.01(a), Stratex’s unaudited financial statements as of June 30, 2012 and March 31, 2012 and audited financial statements for the period January 25, 2011 (Date of Inception) to December 31, 2011 are included with this Current Report beginning on Page F-1.

(b) Pro forma financial information

The pro-forma financial statement is not required as the ongoing results of the Company will be that of the accounting acquirer. The operations of the legal acquirer were split-off at the time of the transaction.

Exhibit No.		Description

2.1		Agreement and Plan of Merger and Reorganization, dated as of June , 2012, by and among Stratex Holdings, Inc. a Colorado corporation, Stratex Acquisition Corp., a Colorado corporation and Stratex Oil & Gas, Inc., a Delaware corporation (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
2.2		State of Delaware Certificate of Merger (Incorporated by reference to Current Report on Form 8-K/A filed on February 27, 2013)
2.3		State of Colorado Statement of Merger (Incorporated by reference to Current Report on Form 8-K/A filed on February 27, 2013)
3.1		Articles of Incorporation of Stratex Acquisition Corp., as filed with the Secretary of State of Colorado on May 24 ,2012 (Incorporated by reference to Current Report on Form 8-K/A filed on February 27, 2013)
3.2		Bylaws of Stratex Oil & Gas, Inc.( Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
3.3		Bylaws of Stratex Acquisition Corp.( Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
3.4		Articles of Amendment of Poway Muffler and Brake, Inc. filed on May 25, 2012 ( incorporated by reference to Current Report on Form 8-K filed June 6, 2012)
4.1		Form of Promissory Note of Stratex Oil & Gas, Inc.( Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
4.2		Form of Warrant of issued to holders of Stratex Oil & Gas, Inc. promissory notes (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
4.3		Form of Note Purchase Agreement (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
4.4		Stratex Oil & Gas Holdings, Inc. Series A Preferred Certificate of Designation (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
10.1		Split-Off Agreement, by and among Stratex Oil & Gas Holdings, Inc., PMB Holdings, Inc., and Allan Ligi (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
10.2		Timothy Kelly Employment Agreement (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)

Exhibit No.		Description
10.3		Stephen Funk Employment Agreement (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
10.4		Stratex Oil & Gas, Inc. 2012 Equity Incentive Plan ***( Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
10.5		Tininenko Well Purchase Agreemen t(Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
10.6		Golden Valley assignment of Oil & Gas Leases (Incorporated by reference to Current Report on Form 8-K/A filed on February 27, 2013)
10.7		Sheridan County Assignment of Oil and Gas Lease (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
10.8		Williams County Oil & Gas Lease (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
10.9		Williams County Oil & Gas Lease Assignment (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
10.10		Nebraska Alliance Assignment, Conveyance and Bill of Sale (Incorporated by reference to Current Report on Form 8-K/A filed on February 27, 2013)
10.11		Rice Lane County Assignment of Overriding Royalty Interest (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
10.12		Assignment, Conveyance and Bill of Sale from Front Range Energy Partners, LLC to Stratex Oil & Gas, Inc. (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
10.13		LaRoche Petroleum Consultants, Ltd. Engagement Letter (Incorporated by reference to Current Report on Form 8-K/A filed on February 27, 2013)
10.14		Geoval Consulting Agreement (Incorporated by reference to Current Report on Form 8-K/A filed on February 27, 2013)
10.15		Form of Brio Financial Group Consulting Agreement (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
16.1		Letter re change in certifying accountant (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
21.1		Subsidiaries of Stratex Holdings, Inc. (Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
99.1		LaRoache Petroleum Consultants, Ltd. Engineering Report as of December 31, 2011(Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)
99.2		Press Release dated July 9, 2012(Incorporated by reference to Current Report on Form 8-K filed July 12, 2012)

***	Designates management contracts and compensation plans

SIGNATURES

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

	STRATEX OIL & GAS HOLDINGS, INC.

Date: February 27, 2012	By:	/s/ Stephen Funk
		Name: Stephen Funk
		Title: Chief Executive Officer

Date: February 27, 2012	By:	/s/ Tim Kelly
		Name: Timothy Kelly
		Title: President and Chief Operating Officer

STRATEX OIL & GAS, INC.

(A DEVELOPMENT STAGE COMPANY)

FINANCIAL STATEMENTS

FOR THE PERIOD JANUARY 25, 2011 (DATE OF INCEPTION) TO DECEMBER 31, 2011

	Page(s)

Report of Independent Registered Public Accounting Firm	F-2

Balance Sheet - December 31, 2011	F-3

Statement of Operations - Period January 25, 2011 (Date of Inception) to December 31, 2011	F-4

Statement of Stockholders’ Equity - Period January 25, 2011 (Date of Inception) to December 31, 2011	F-5

Statement of Cash Flows – Period January 25, 2011 (Date of Inception) to December 31, 2011	F-6

Notes to Financial Statements	F-7 to F-22

F-1

MAHONEY SABOL & COMPANY, LLP

95 GLASTONBURY BOULEVARD

GLASTONBURY, CONNECTICUT 06033

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of Stratex Oil & Gas, Inc.

We have audited the accompanying balance sheet of Stratex Oil & Gas, Inc. (a development stage company) as of December 31, 2011, and the related statements of operations, stockholders' equity and cash flows for the period from January 25, 2011 (date of inception) to December 31, 2011. Stratex Oil & Gas, Inc.'s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Stratex Oil & Gas, Inc. as of December 31, 2011, and the results of its operations and its cash flows for the period from January 25, 2011 (date of inception) to December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the company will continue as a going concern. As discussed in Note 1 to the financial statements, the company has suffered losses from operations and has an accumulated deficit, which raise substantial doubt about its ability to continue as a going concern. Management's plans regarding those matters also are described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/S/ MAHONEY SABOL & COMPANY, LLP

Glastonbury, Connecticut

June 27, 2012

F-2

Stratex Oil & Gas, Inc.
(A Development Stage Company)
Balance Sheet



	December 31, 2011

Assets

Current Assets:
Cash	$	585,805
Accounts receivable, net		28,336
Inventory		43,189
Subscriptions receivable		15,400
Prepaid expenses		1,800
Debt issuance costs		24,458
Total Current Assets		698,988

Deposits		10,000
Oil and gas property, plant and equipment:
Proven property - net		595,547
Unproven property		2,193,682
Furniture and equipment		1,536
Total Assets	$	3,499,753

Liabilities and Stockholders' Equity

Current Liabilities:
Accounts payable and accrued liabilities	$	117,742
Notes payable, net of debt discount		1,111,440
Derivative liability - warrants		316,924
Total Current Liabilities		1,546,106


Total Liabilities		1,546,106

Stockholders' Equity
Series A, convertible preferred stock, $0.0001 par value; 100
shares authorized, none issued and outstanding		-
Common stock, $0.0001 par value; 125,000,000 shares authorized;
and 52,952,585 shares issued and outstanding		5,295
Additional paid in capital		2,932,911
Deficit accumulated during the development stage		(984,559	)
Total Stockholders' Equity		1,953,647

Total Liabilities and Stockholders' Equity	$	3,499,753

F-3

Stratex Oil & Gas, Inc.
(A Development Stage Company)
Statement of Operations

	January 25, 2011
	(Date of Inception)
	through
	December 31,
	2011

Revenue	$	240,122

Operating expense:
Production expenses		101,265
Depletion, depreciation and amortization		110,793
General and administrative		828,229
Total operating expenses		1,040,287

Loss from operations		(800,165	)

Other Income and Expense:
Interest expense		(183,692	)
Change in fair value - derivative liabilities		(702	)
Total other income and expense		(184,394	)


Net loss	$	(984,559	)

Net loss per common share - basic and diluted	$	(0.03	)

Weighted average common shares outstanding
- basic and diluted		31,116,374

F-4

Stratex Oil & Gas, Inc.
(A Development Stage Company)
Statement of Stockholders' Equity
For the Period from January 25, 2011 (Date of Inception) to December 31, 2011

					Additional			Deficit Accumulated during the
	Common Stock				Paid-In			Development			Stockholders'
	Shares		Amount		Capital			Stage			Equity

Balance, January 25, 2011 (Date of Inception)		-		-		-			-			-

Common stock issued to founders		10,500,000		1,050		(1,050	)		-			-

Common stock issued for cash ($0.007/share - $0.25/share)		37,341,000		3,734		2,231,875			-			2,235,609

Common stock issued for subscription receivable ($0.007/share)		2,200,000		220		15,180			-			15,400

Common stock issued for property		75,000		7		18,743			-			18,750

Conversion of notes payable and interest to common stock		2,476,585		248		618,899			-			619,147

Stock issued for services		360,000		36		74,964			-			75,000

Stock issuance costs		-		-		(25,700	)		-			(25,700	)

Net loss, December 31, 2011									(984,559	)		(984,559	)

Balance, December 31, 2011		52,952,585	$	5,295	$	2,932,911		$	(984,559	)	$	1,953,647

F-5

Stratex Oil & Gas, Inc.
(A Development Stage Company)
Statement of Cash Flows


	January 25, 2011
	(Date of Inception)
	through
	December 31,
	2011
Cash Flows From Operating Activities:
Net loss	$	(984,559	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization		110,793
Stock based compensation		75,000
Amortization of debt issue costs		10,042
Accretion of debt discount		137,662
Change in fair value of derivative liabilities		702
Changes in operating assets and liabilities:
(Increase) decrease in:
Accounts receivable		(28,336	)
Prepaid expenses		(1,800	)
Inventory		(43,189	)
Increase (decrease) in:
Accounts payable and accrued liabilities		121,889
Net Cash Used In Operating Activities		(601,796	)

Cash Flows From Investing Activities:
Purchase of oil and gas properties		(2,881,182	)
Deposit on property		(10,000	)
Purchase of furniture and equipment		(1,626	)
Net Cash Used In Investing Activities		(2,892,808	)

Cash Flows From Financing Activities:
Proceeds from notes payable		2,135,000
Repayments on notes payable		(230,000	)
Debt issuance costs paid in cash		(34,500	)
Sale of common stock for cash		2,235,609
Stock issuance costs paid in cash		(25,700	)
Net Cash Provided By Financing Activities		4,080,409

Net change in cash		585,805

Cash at beginning of period		-

Cash at end of period	$	585,805

Supplemental disclosures of cash flow information:
Cash paid for interest	$	4,225
Cash paid for taxes	$	-

Supplemental disclosure of non-cash investing and financing activities:

Conversion of notes payable and accrued interest to common stock	$	619,147
Issuance of common stock for a subscription receivable	$	15,400
Purchase of property for common stock	$	18,750
Original issue discount on notes payable	$	138,000
Derivative liability recorded to debt discount at issuance of notes payable	$	316,222

F-6

Note 1 Nature of Operations and Basis of Presentation

Nature of Operations

Stratex Oil & Gas, Inc. (the Company), is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves in the Bakken, Three Forks, Heath and Tyler Formations in North Dakota, Montana, Kansas, Nebraska and Colorado.

The Company was originally organized as a Connecticut corporation on January 25, 2011. Effective February 18, 2011 the Company converted to a Delaware corporation. The Company was originally authorized to issue 40,000 shares of common stock, $0.0001 par value per share. By certificates of amendment dated April 1, 2011 and March 30, 2012, the authorized shares of common stock were increased to 85,000,000 shares and 125,000,000 shares, respectively. In addition, the April 1, 2011 certificate of amendment authorized the Company to issue up to 100 shares of preferred stock, $0.0001 par value per share.

The Company’s major assets are an oil well in Roosevelt County, Montana and leaseholds affording drilling rights in North Dakota, Montana, Kansas, Nebraska and Colorado.

Development Stage Company

The Company is a development stage enterprise since it has not yet generated substantial revenue from the sale of oil and gas and, through December 31, 2011, its efforts have been principally devoted to the regulatory, legal and research requirements for the development of a portfolio of proven oil and gas reserves. The accompanying financial statements have been prepared in accordance with the provisions of Financial Accounting Standards Board Accounting Standards Codification (FASB ASC) 915-205-45.

Going Concern

As reflected in the accompanying financial statements, the Company has a net loss of $984,559 and net cash used in operations of $601,796 for the period January 25, 2011 (Date of Inception) to December 31, 2011; and has a working capital deficit of $847,118.

The ability of the Company to continue its operations is dependent on Management's plans, which include the raising of capital through debt and/or equity markets with some additional funding from other traditional financing sources, including term notes, until such time that funds provided by operations are sufficient to fund working capital requirements. The Company may need to incur additional liabilities with certain related parties to sustain the Company’s existence.

The Company will require additional funding to finance the growth of its current and expected future operations as well as to achieve its strategic objectives. The Company believes its current available cash along with anticipated revenues may be insufficient to meet its cash needs for the near future. There can be no assurance that financing will be available in amounts or terms acceptable to the Company, if at all.

The accompanying financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. These financial statements do not include any adjustments relating to the recovery of the recorded assets or the classification of the liabilities that might be necessary should the Company be unable to continue as a going concern.

F-7

Note 2 Summary of Significant Accounting Policies

Use of estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Such estimates and assumptions impact, among others, the following: allowance for bad debt, inventory obsolescence, the fair value of share-based payments, fair value of derivative liabilities, estimates of the probability and potential magnitude of contingent liabilities and the valuation allowance for deferred tax assets due to continuing operating losses.

Making estimates requires management to exercise significant judgment. It is at least reasonably possible that the estimate of the effect of a condition, situation or set of circumstances that existed at the date of the financial statements, which management considered in formulating its estimate could change in the near term due to one or more future confirming events. Accordingly, the actual results could differ significantly from our estimates.

The accompanying financial statements contain estimates of the Company’s proved reserves and the estimated future net revenues from the proved reserves. These estimates are based on various assumptions, including assumptions required by the United States Securities and Exchange Commission (“SEC”) relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

The process of estimating oil and gas reserves is complex and involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, the Company’s management may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond the Company’s control. The Company’s properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

The present value of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of the Company’s estimated oil and natural gas reserves. The estimated discounted future net cash flows from the Company’s proved reserves is based on the average, first-day-of-the-month price during the 12-month period preceding the measurement date. Actual future net cash flows from oil and natural gas properties also will be affected by factors such as actual prices received for oil and gas, actual development and production costs, the amount and timing of actual production, the supply of and demand for oil and gas, and changes in governmental regulations or taxes.

The timing of the Company’s production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor used when calculating discounted future net cash flows for financial statement disclosure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.

Included in this report are estimates of the Company’s proved reserves at December 31, 2011 as prepared consistent with the Company’s independent reserve engineers’ interpretations of the SEC rules relating to disclosures of estimated natural gas and oil reserves. These rules require SEC reporting companies to prepare their reserve estimates using reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. While estimates of the Company’s proved reserves at December 31, 2011 included in this report have been prepared based on what Management and the Company’s independent reserve engineers believe to be reasonable interpretations of the SEC rules, those estimates could ultimately differ materially from any estimates that may be prepared in applying more specific SEC interpretive guidance.

F-8

Risks and uncertainties

The Company operates in an industry that is subject to intense competition and change in consumer demand. The Company's operations are subject to significant risk and uncertainties including financial and operational risks including the potential risk of business failure.

The Company’s future success depends largely on its ability to find and develop or acquire additional oil and gas reserves that are economically recoverable. Unless the Company replaces the reserves produced through successful development, exploration or acquisition activities, proved reserves will decline over time. Recovery of any additional reserves will require significant capital expenditures and successful drilling operations. The Company may not be able to successfully find and produce reserves economically in the future. In addition, the Company may not be able to acquire proved reserves at acceptable costs.

Cash and cash equivalents

The Company considers all highly liquid instruments purchased with a maturity of three months or less to be cash equivalents. There were no cash equivalents at December 31, 2011.

The Company minimizes its credit risk associated with cash by periodically evaluating the credit quality of its primary financial institution.

Accounts receivable and allowance for doubtful accounts

Accounts receivable consist primarily of oil and gas receivables, net of a valuation allowance for doubtful accounts. As of December 31, 2011, the allowance for doubtful accounts was $0.

Inventories

Inventories are stated at the lower of cost or market using the first-in, first-out (FIFO) valuation method.

	December 31, 2011

Finished goods	$	43,189
Reserve		(-	)
	$	43,189

Oil and Gas Properties, Successful Efforts Method

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under the successful efforts method, costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred. The Company evaluates its proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. The Company follows Accounting Standards Codification ASC 360 - Property, Plant, and Equipment, for these evaluations. Unamortized capital costs are reduced to fair value if the undiscounted future net cash flows from our interest in the property’s estimated proved reserves are less than the asset’s net book value.

Support Facilities and Equipment

Our support facilities and equipment are generally located in proximity to certain of our principal fields. Depreciation of these support facilities is provided on the straight-line method based on estimated useful lives of 7 to 20 years.

Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.

F-9

Proved Reserves

Estimates of the Company’s proved reserves included in this report are prepared in accordance with GAAP and guidelines from the SEC. The Company’s engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and impairment. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions, and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of the Company’s estimated proved reserves. The Company engages independent reserve engineers to estimate its proved reserves.

Asset Retirement Obligations

The Company follows the provisions of the Accounting Standards Codification ASC 410 - Asset Retirement and Environmental Obligations. The fair value of an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. As of December 31, 2011, the Company’s obligations were immaterial. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. The Company’s asset retirement obligations relate to the abandonment of oil and gas producing facilities. The amounts recognized are based upon numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and gas, future inflation rates and the credit-adjusted risk-free interest rate.

Debt Issue Costs and Debt Discount

The Company may pay debt issue costs, and record debt discounts in connection with raising funds through the issuance of convertible debt. These costs are amortized over the life of the debt to interest expense. If a conversion of the underlying debt occurs, a proportionate share of the unamortized amounts is immediately expensed.

Original Issue Discount

For certain convertible debt issued from January 25, 2011 through December 31, 2011, the Company provided the debt holder with an original issue discount. The original issue discount was equal to three years of simple interest at 10% of the proceeds raised. The original issue discount was recorded to debt discount reducing the face amount of the note and is being amortized to interest expense over the maturity period of the debt.

Derivative Financial Instruments

Fair value accounting requires bifurcation of embedded derivative instruments such as ratchet provisions or conversion features in convertible debt or equity instruments, and measurement of their fair value for accounting purposes. In determining the appropriate fair value, the Company utilized an option pricing model. In assessing the Company’s convertible debt instruments, management determines if the convertible debt host instrument is conventional convertible debt and further if there is a beneficial conversion feature requiring measurement. If the instrument is not considered conventional convertible debt, the Company will continue its evaluation process of these instruments as derivative financial instruments.

F-10

Once determined, the derivative liabilities are adjusted to reflect fair value at each reporting period end, with any increase or decrease in the fair value being recorded in results of operations as an adjustment to fair value of derivatives. In addition, the fair value of freestanding derivative instruments such as warrants, are also valued using the option pricing model.

Revenue recognition

Revenues from the sale of oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company follows the “sales method” of accounting for oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than its share of the expected remaining proved reserves.

Share-based payments

Generally, all forms of share-based payments, including stock option grants, warrants, restricted stock grants and stock appreciation rights are measured at their fair value utilizing an option pricing model on the awards’ grant date, based on the estimated number of awards that are ultimately expected to vest. Share-based compensation awards issued to non-employees for services rendered are recorded at either the fair value of the services rendered or the fair value of the share-based payment, whichever is more readily determinable. The expenses resulting from share-based payments are recorded in cost of goods sold or general and administrative expense in the statement of operations, depending on the nature of the services provided.

Income Taxes

The Company is a taxable entity and recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect when the temporary differences reverse. The effect on the deferred tax assets and liabilities of a change in tax rates is recognized in income in the year that includes the enactment date of the rate change. A valuation allowance is used to reduce deferred tax assets to the amount that is more likely than not to be realized. Interest and penalties associated with income taxes are included in selling, general and administrative expense.

The Company has adopted ASC 740 “Accounting for Uncertainty in Income Taxes” which prescribes a comprehensive model of how a company should recognize, measure, present, and disclose in its financial statements uncertain tax positions that the company has taken or expects to take on a tax return. ASC 740 states that a tax benefit from an uncertain position may be recognized if it is "more likely than not" that the position is sustainable, based upon its technical merits. The tax benefit of a qualifying position is the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority having full knowledge of all relevant information.

Earnings per share

Basic earnings (loss) per share is computed by dividing net income (loss) by weighted average number of shares of common stock outstanding during each period. Diluted earnings (loss) per share is computed by dividing net income (loss), adjusted for changes in income or loss that resulted from the assumed conversion of convertible shares, by the weighted average number of shares of common stock, common stock equivalents and potentially dilutive securities outstanding during the period.

F-11

The Company had the following potential common stock equivalents at December 31, 2011:

Convertible debt – face amount of $1,428,000, conversion price of $0.35			4,080,000
Common stock warrants, exercise price of $0.35			1,290,000
Total common stock equivalents			5,370,000

Since the Company reflected a net loss in 2011, the effect of considering any common stock equivalents, would have been anti-dilutive. A separate computation of diluted earnings (loss) per share is not presented.

Fair Value of Financial Instruments

The Company follows paragraph 820-10-35-37 of the FASB Accounting Standards Codification (“Paragraph 820-10-35-37”) to measure the fair value of its financial instruments and paragraph 825-10-50-10 of the FASB Accounting Standards Codification for disclosures about fair value of its financial instruments. Paragraph 820-10-35-37 establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America (U.S. GAAP), and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, Paragraph 820-10-35-37 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The three (3) levels of fair value hierarchy defined by Paragraph 820-10-35-37 are described below:

Level 1		Quoted market prices available in active markets for identical assets or liabilities as of the reporting date.

Level 2		Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3		Pricing inputs that are generally observable inputs and not corroborated by market data.

Financial assets are considered Level 3 when their fair values are determined using pricing models, discounted cash flow methodologies or similar techniques and at least one significant model assumption or input is unobservable.

The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

The carrying amounts of the Company’s financial assets and liabilities, such as cash, prepaid expenses and other current assets, accounts payable and accrued liabilities approximate their fair values because of the short maturity of these instruments.

The Company’s notes payable approximate the fair value of such instruments based upon management’s best estimate of interest rates that would be available to the Company for similar financial arrangements at December 31, 2011.

The Company’s Level 3 financial liabilities consist of the derivative warrant issued with the 2011 notes payables for which there is no current market for this security such that the determination of fair value requires significant judgment or estimation. The Company valued the reset adjustments in the warrant on subsequent potential equity offerings using an option pricing model, for which management understands the methodologies. These models incorporate transaction details such as the Company’s stock price, contractual terms, maturity, risk free rates, as well as assumptions about future financings, volatility, and holder behavior as of the date of issuance and each balance sheet date.

F-12

Transactions involving related parties cannot be presumed to be carried out on an arm's-length basis, as the requisite conditions of competitive, free-market dealings may not exist. Representations about transactions with related parties, if made, shall not imply that the related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions unless such representations can be substantiated.

Fair Value of Financial Assets and Liabilities Measured on a Recurring Basis

The Company uses Level 3 of the fair value hierarchy to measure the fair value of the derivative liabilities and revalues its derivative warrant liability and derivative feature of convertible notes at every reporting period and recognizes gains or losses in the statements of operations attributable to the change in the fair value of the derivatives.

Financial assets and liabilities measured at fair value on a recurring basis are summarized below and disclosed on the balance sheets as follows:

December 31, 2011	Fair Value Measurement Using

	Level 1			Level 2			Level 3			Total

Derivative warrant liabilities		$	-		$	-		$	316,924		$	316,924

The table below provides a summary of the changes in fair value, including net transfers in and/or out, of all financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period ended December 31, 2011:

	Fair Value Measurement Using Level 3 Inputs
			Derivative Liabilities		Total

Balance, January 25, 2011 (Date of Inception)		$	-	$	-

Purchases, issuances and settlements			316,222		316,222

Total gains or losses (realized/unrealized)
included in net loss			702		702

Transfers in and/or out of Level 3			-		-

Balance, December 31, 2011		$	316,924	$	316,924

F-13

Recent accounting pronouncements

In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The guidance in ASU 2011-04 changes the wording used to describe the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements, including clarification of the FASB's intent about the application of existing fair value and disclosure requirements and changing a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The amendments in this ASU should be applied prospectively and are effective for interim and annual periods beginning after December 15, 2011. Early adoption by public entities is not permitted. The adoption of this guidance is not expected to have a material impact on the Company’s financial position or results of operations.

Note 3 Oil and Gas Assets:

The following table summarizes the oil and gas assets:

Cost January 25, 2011 (Date of Inception)	$	-
Additions		2,765,232
Depletion		(103,968	)
Impairment		-
Balance – December 31, 2011	$	2,661,264

The Company owns support facilities and equipment which serve its oil and gas production activities. The following table details these properties and equipment, together with their estimated useful lives:

Cost January 25, 2011 (Date of Inception)	$	-
Additions		134,700
Depletion		(6,735	)
Impairment		-
Balance – December 31, 2011	$	127,965

During the period ended December 31, 2011, the Company recorded $110,703 to depletion expense.

Note 4 Furniture and Equipment:

The following table summarizes furniture and equipment:

Cost January 25, 2011 (Date of Inception)	$	-
Additions		1,626
Depreciation		(90	)
Impairment		-
Balance – December 31, 2011	$	1,536

During the period ended December 31, 2011, the Company recorded $90 to depreciation expense.

F-14

Note 5 Notes Payable

(A)	Notes Payable – 10%

During the period February 22, 2011 to June 6, 2011, the Company issued nineteen (19) promissory notes to certain accredited investors in an aggregate amount of $845,000. The loans bear 10% interest. These loans have a maturity of 6 months and are unsecured.

During the period ended December 31, 2011, fifteen (15) noteholders converted $615,000 in notes payable and $4,147 of accrued interest into 2,476,585 shares of the Company’s common stock at a conversion rate of $0.25/share.

During the period ended December 31, 2011, three (3) noteholders were re-paid $230,000 in principal.

The following is a summary of notes payable – related parties:

Balance – January 25, 2011(Date of Inception)	$	-
Issuance of notes payable		845,000
Repayments		(230,000	)
Converted to common stock		(615,000	)
Balance – December 31, 2010	$	-

(B) Notes Payable – Convertible

On October 19, 2011, the Company sold a convertible promissory note in the aggregate principal amount of $1,100,000 for proceeds of $1,000,000 payable May 24, 2012 and a 5 year common stock purchase warrant exercisable for up to 1,000,000 shares of common stock at $0.35 per share to an accredited investor. The note is convertible at a rate of $0.35 per share. The note is unsecured.

During the period ended December 31, 2011, the Company sold 4 convertible promissory notes in the aggregate principal amount of $328,000 for proceeds of $300,000 with a one year maturity and a 5 year common stock purchase warrant exercisable for up to 290,000 shares of common stock at $0.35 per shares to an accredited investor. The note is convertible at a rate of $0.35 per share. The note is unsecured.

The following is a summary of notes payable – related parties:

Balance – January 25, 2011 (Date of Inception)	$	-
Issuance of convertible notes payable		1,428,000
Original issue discount		(138,000	)
Discount recorded on derivative liability at issuance		(316,222	)
Repayments		(-	)
Converted to common stock		(-	)
Accretion of debt discount		137,662
Balance – December 31, 2011	$	1,111,440

F-15

Debt issuance costs, net are as follows:

Balance – January 25, 2011 (Date of Inception)	$	-
Debt issue costs paid in 2011		34,500
Amortization of debt issue costs		(10,042	)
Balance - December 31, 2011	$	24,458

Note 6 Stockholders Equity

(A)	Common Stock

During the period ended December 31, 2011, the Company issued the following common stock:

Transaction Type	Quantity of Shares		Valuation		Range of Value per Share
Founder shares		10,500,000	$	-	$	-
Issued for cash		37,341,000	$	2,235,609	$	0.007 - $0.25
Issued for subscription receivable		2,200,000	$	15,400	$	0.007
Issued for purchase of property		75,000	$	18,750	$	0.25
Services rendered – consultants		360,000	$	75,000	$	0.007 - $0.25
Conversion of debt and interest		2,476,585	$	619,147	$	0.25

Total		52,952,585	$	2,963,906	$	0.007 - $0.25

The following is a summary of the Company’s warrant activity:

	Warrants		Weighted Average Exercise Price

Outstanding – January 25, 2011(Date of Inception)		-	$	-
Exercisable – January 25, 2011 (Date of Inception)		-	$	-
Granted		1,290,000	$	0.35
Exercised		-	$	-
Forfeited/Cancelled		-	$	-
Outstanding – December 31, 2011		1,290,000	$	0.35
Exercisable – December 31, 2011		1,290,000	$	0.35

Warrants Outstanding								Warrants Exercisable
Range of exercise price		Number Outstanding		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Number Exercisable		Weighted Average Exercise Price
$	0.35		1,290,000		4.85	$	0.35		1,290,000	$	0.35

At December 31, 2011, the total intrinsic value of warrants outstanding and exercisable was $0.

F-16

Note 7 Commitments and Contingencies

Litigations, Claims and Assessments

From time to time, the Company may become involved in various lawsuits and legal proceedings, which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm its business. The Company is currently not aware of any such legal proceedings or claims that they believe will have, individually or in the aggregate, a material adverse effect on its business, financial condition or operating results.

On May 18, 2012, Stratex filed a complaint against Petrogulf Corporation in the U.S. District Court for the District of North Dakota alleging breach of an agreement to assign to Stratex a non-operating, working interest in certain oil wells and oil and gas leases. Stratex seeks specific performance of the disputed agreement, an award of compensatory damages to be determined at trial, but in no event less than $50 million, plus interest, costs incurred in connection with this litigation and such relief as the court may deem proper. Petrogulf Corporation seeks declaratory judgment and monetary damages related to and arising from our complaint filing.

Oil and Gas Prices

The prices of oil, natural gas, methane gas and other fuels have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to numerous factors, including but not limited to the worldwide and domestic supplies of oil and gas, changes in the supply of and demand for such fuels, political conditions in fuel-producing and fuel-consuming regions, weather conditions, the development of other energy sources, and the effect of government regulation on the production, transportation and sale of fuels. These factors and the volatility of energy markets make it extremely difficult to predict future oil and gas price movements with any certainty. A decline in prices could adversely affect the Company’s financial position, financial results, cash flows, access to capital and ability to grow.

Environmental Liabilities

Oil and gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or other well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings, and separated cables. If any of these circumstances occur, the Company could sustain substantial losses as a result of injury or loss of life, destruction of property and equipment, damage to national resources, pollution or other environmental damages, clean-up responsibilities, regulatory investigations and penalties, suspension of operations, and compliance with environmental laws and regulations relating to air emissions, waste disposal and hydraulic fracturing, restrictions on drilling and completion operations and other laws and regulations. The Company’s potential liability for environmental hazards may include those created by the previous owners of properties purchased or leased prior to the date we purchase or lease the property. The Company maintains insurance against some, but not all, of the risks described above. Insurance coverage may not be adequate to cover casualty losses or liabilities.

Note 8 Income Taxes

At December 31, 2011, the Company has a net operating loss carry-forward of approximately $750,000 available to offset future taxable income expiring through 2031. Utilization of these net operating losses may be limited due to potential ownership changes under Section 382 of the Internal Revenue Code.

F-17

The valuation allowance at December 31, 2011 was $288,000. The net change in valuation allowance during the year ended December 31, 2011 was an increase of $288,000. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred income tax assets will not be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred income tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based on consideration of these items, Management has determined that enough uncertainty exists relative to the realization of the deferred income tax asset balances to warrant the application of a full valuation allowance as of December 31, 2011.

Significant deferred tax assets at December 31, 2011 are as follows:

	2011
Gross deferred tax assets:
Net operating loss carryforward	$	288,000
Total deferred tax assets		288,000
Less: valuation allowance		(288,000)
Deferred tax asset – net	$	-

There was no income tax expense for the years ended December 31, 2011 due to the Company’s net losses.

The Company’s tax expense differs from the “expected” tax expense for the years ended December 31, 2011, (computed by applying the Federal Corporate tax rate of 34% to loss before tax and 6.75% for State Corporate taxes for the years ended December 31, 2011, the blended rate used was 38% for the year ended December 31, 2011, as follows:

	2011

Expected tax expense (benefit) – Federal	$	(312,000	)
Expected tax expense (benefit) – State		(66,000	)
Non-deductible stock compensation		29,000
Non-deductible meals and entertainment		4,000
Derivative Expense		-
Change in fair value of derivative expense		-
Amortization of debt discount And issuance costs		57,000
Change in Valuation Allowance		288,000
Actual tax expense (benefit)		-

The following is a reconciliation of the provision for income taxes at the United States federal income tax rate to the income taxes reflected in the statement of operations:

	December 31, 2011
Tax expense (credit) at statutory rate-federal		31%
State tax expense net of federal tax		7%
Changes in valuation allowance		(38%)
Tax expense at actual rate		-

F-18

Note 9 Subsequent Events

The Company has evaluated for any subsequent events through June 27, 2012, which is the date these financial statements were available to be issued.

Common Stock Issuances

During the period January 1, 2012 to June 27, 2012, the company sold 11,287,857 shares of the Company’s common stock for gross proceeds of $1,637,295.

On February 1, 2011, the Company issued 300,000 shares of the company’s common stock for services rendered. The Company valued the services at $75,000 or $0.25/share.

On April 19, 2012, a noteholder converted $25,000 of principal and interest of $1,165 into 104,658 shares of the company’s common stock at a conversion rate of $0.25/share.

Employment Contracts

On April 1, 2012, the Company entered into an Executive Employment Agreement with the Chief Executive Officer. The terms of the Agreement are as follows:

●	Term - 5 years,
●	Compensation - $250,000 salary per annum, bonus eligibility, (annual raises equal to 10%)
●	Option Grant - 3,000,000 options to acquire restricted stock,
·	Preferred Share Grant - 50 shares of Preferred Stock which entitle the CEO to 50 million votes on all matters submitted to a vote of the shareholders of the Company.

On April 1, 2012, the Company entered into an Executive Employment Agreement with the Chief Operating Officer. The terms of the Agreement are as follows:

●	Term - 5 years,
●	Compensation - $250,000 salary per annum, bonus eligibility, (annual raises equal to 10%)
●	Option Grant - 3,000,000 options to acquire restricted stock,
●	Preferred Share Grant - 50 shares of Preferred Stock which entitle the COO to 50 million votes on all matters submitted to a vote of the shareholders of the Company.

F-19

Note 10. Supplemental Information on Oil and Gas Operations (Unaudited):

This supplementary oil and natural gas information is provided in accordance with the United States Financial Accounting Standards Board (“FASB”) Topic 932 - “Extractive Activities - Oil and Gas”.

The Company retains qualified independent reserves evaluators to evaluate the Company’s proved oil reserves. The Company does not have any natural gas reserves. For the year ended December 31, 2011 the report by LaRoche Petroleum Consultants (“LaRoche”) covered 100% of the Company’s proved oil reserves.

Proved oil and natural gas reserves, as defined within the SEC Rule 4-10(a)(22) of Regulation S-X, 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 of which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether determinable 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. Developed oil and natural gas reserves are reserves that can be expected to be recovered from 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 through installed extraction equipment and infrastructure operational at the time of the reserves estimate is the extraction is by means not involving a well. Estimates of the Company’s oil reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change.

The following table summarizes the Company’s proved developed and undeveloped reserves (all oil) within the United States, net of royalties, as of December 31, 2011:

Oil (MBbls)	2011

Proved reserves as at January 1		-
Extensions and discoveries		-
Additions		13
Dispositions		-
Production		-
Revisions of prior estimates		-
Total Proved reserves as at December 31		13

Oil (MBbls)		2011

Proved developed producing		13
Non-producing		-
Proved undeveloped		-
Total Proved reserves as at December 31		13

F-20

Capitalized Costs Related to Oil and Gas Assets	2011

Proved properties	$	595,000
Unproved properties		2,194,000
		2,789,000
Less: accumulated impairment		-
Less: accumulated depletion		(104,000	)
	$	2,685,000


Costs incurred in Oil and Gas Activities:		2011

Purchase and development	$	2,881,000
Exploration		-
	$	2,881,000

Standardized Measure of Discounted Future Net Cash Flows From Proved Oil Reserves and Changes Therein:

The following standardized measure of discounted future net cash flows from proved oil reserves has been computed using the average first-day-of-the-month price during the previous 12-month period, costs as at the balance sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair value of the oil properties. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including:

•	Future production will include production not only from proved properties, but may also include production from probable and possible reserves;

•	Future production of oil and natural gas from proved properties may differ from reserves estimated;

•	Future production rates may vary from those estimated;

•	Future rather than average first-day-of-the-month prices during the previous 12-month period and costs as at the balance sheet date will apply;

•	Economic factors such as changes to interest rates, income tax rates, regulatory and fiscal environments and operating conditions cannot be determined with certainty;

•	Future estimated income taxes do not take into account the effects of future exploration expenditures; and

•	Future development and asset retirement obligations may differ from those estimated.

F-21

Future net revenues, development, production and restoration costs have been based upon the estimates referred to above. The following tables summarize the Company’s future net cash flows relating to proved oil reserves based on the standardized measure as prescribed in FASB Topic 932 - “Extractive Activities - Oil and Gas”:

Future cash flows relating to proved reserves:	2011

Future cash inflows	$	1,106,000
Future operating costs		(452,000	)
Future development costs		(30,000	)
Future income taxes		(214,000)
Future net cash flows		410,000
10% discount factor		(14,000	)
Standardized measure	$	396,000


Reconciliation of future cash flows relating to proved reserves:		2011

Undiscounted value as of January 1	$	-
Purchases		410,000
Extensions and discoveries		-
Dispositions		-
Production		-
Revisions of prior volume estimates		-
Revisions of pricing		-
Undiscounted value as at December 31		410,000
10% discount factor		(14,000	)
Standardized measure	$	396,000

F-22

STRATEX OIL & GAS, INC.

(A DEVELOPMENT STAGE COMPANY)

FINANCIAL STATEMENTS (UNAUDITED)

FOR THE PERIOD JANUARY 25, 2011 (DATE OF INCEPTION) TO JUNE 30, 2012

F-23

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

	Page(s)

Balance Sheets – June 30, 2012 (unaudited) and December 31, 2011	F-25

Statements of Operations – For the three and six months ended June 30, 2012 and 2011 (unaudited) and for the period January 25, 2011 (Date of Inception) to June 30, 2012 (unaudited)	F-26

Statement of Stockholders’ Equity – Period January 25, 2011 (Date of Inception) to June 30, 2012 (unaudited)	F-27

Statements of Cash Flows – For the six months ended June 30, 2012 and 2011 (unaudited) and for the period January 25, 2011 (Date of Inception) to June 30, 2012 (unaudited)	F-28

Notes to Financial Statements (unaudited)	F-29 - F-43

F-24

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Balance Sheets

	June 30, 2012			December 31, 2011
	(unaudited)

Assets

Current Assets:
Cash	$	431,109		$	585,805
Accounts receivable, net		61,614			28,336
Inventory		39,119			43,189
Subscriptions receivable		12,065			15,400
Prepaid expenses		5,229			1,800
Debt issuance costs		2,356			24,458
Total Current Assets		551,492			698,988

Deposits		10,000			10,000
Oil and gas property, plant and equipment:
Proven property - net		509,060			595,547
Unproven property		2,665,912			2,193,682
Furniture and equipment		1,265			1,536
Total Assets	$	3,737,729		$	3,499,753

Liabilities and Stockholders' Equity

Current Liabilities:
Accounts payable and accrued liabilities	$	275,073		$	117,742
Notes payable, net of debt discount		253,037			1,111,440
Derivative liability - warrants		322,116			316,924
Total Current Liabilities		850,226			1,546,106

Total Liabilities		850,226			1,546,106

Stockholders' Equity:
Series A, convertible preferred stock, $0.0001 par value; 100 shares authorized;
and 100 and 0 shares issued and outstanding		19			-
Common stock, $0.0001 par value; 85,000,000 and 125,000,000 shares authorized;
and 64,645,100 and 52,952,585 shares issued and outstanding		6,465			5,295
Additional paid in capital		4,983,482			2,932,911
Deficit accumulated during the development stage		(2,102,463	)		(984,559	)
Total Stockholders' Equity		2,887,503			1,953,647

Total Liabilities and Stockholders' Equity	$	3,737,729		$	3,499,753

See accompanying notes to financial statements

F-25

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Statements of Operation

													January 25, 2011
													(Date of Inception)
													through
	For the three months ended June 30,						For the six months ended June 30,						June 30,
	2012			2011			2012			2011			2012
	(unaudited)			(unaudited)			(unaudited)			(unaudited)			(unaudited)

Revenue	$	237,419		$	-		$	457,630		$	-		$	697,752

Operating expenses:
Production expenses		52,941			-			121,245			-			222,510
Depletion, depreciation and amortization		100,459			-			167,662			-			278,455
General and administrative		694,362			222,253			975,945			251,613			1,804,174
Total operating expenses		847,762			222,253			1,264,852			251,613			2,305,139

Loss from operations		(610,343	)		(222,253	)		(807,222	)		(251,613	)		(1,607,387	)

Other Income and Expense:
Interest income		141			-			675			-			675
Interest expense		(93,782	)		(16,703	)		(323,948	)		(16,703	)		(507,640	)
Change in fair value - derivative liabilities		7,538			-			12,591			-			11,889
Total other income and expense		(86,103	)		(16,703	)		(310,682	)		(16,703	)		(495,076	)

Net loss	$	(696,446	)	$	(238,956	)	$	(1,117,904	)	$	(268,316	)	$	(2,102,463	)

Net loss per common share - basic and diluted	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.02	)

Weighted average common shares outstanding
- basic and diluted		60,468,515			19,782,198			57,088,572			12,661,667

See accompanying notes to financial statements

F-26

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Statement of Stockholders' Equity (unaudited)

For the Period from January 25, 2011 (Date of Inception) to June 30, 2012

	Series "A"								Additional			Deficit Accumulated during the
	Preferred Stock				Common Stock				Paid-In			Development			Stockholders'
	Shares		Amount		Shares		Amount		Capital			Stage			Equity

Balance, January 25, 2011 (Date of Inception)		-	$	-		-	$	-	$	-		$	-		$	-

Common stock issued to founders		-		-		10,500,000		1,050		(1,050	)		-			-

Common stock issued for cash ($0.007/share - $0.25/share)		-		-		37,341,000		3,734		2,231,875			-			2,235,609

Common stock issued for subscription receivable ($0.007/share)		-		-		2,200,000		220		15,180			-			15,400

Common stock issued for property		-		-		75,000		7		18,743			-			18,750

Conversion of notes payable and interest to common stock		-		-		2,476,585		248		618,899			-			619,147

Stock issued for services		-		-		360,000		36		74,964			-			75,000

Stock issuance costs		-		-		-		-		(25,700	)		-			(25,700	)

Net loss, December 31, 2011													(984,559	)		(984,559	)

Balance, December 31, 2011		-	$	-		52,952,585	$	5,295	$	2,932,911		$	(984,559	)	$	1,953,647

Series "A" Preferred stock issued for services ($1,941.77/share)		100		19		-		-		194,158			-			194,177

Common stock issued for cash ($0.007/share - $0.35/share)		-		-		5,707,143		571		519,659			-			520,230

Common stock issued for subscription receivable ($0.007/share)		-		-		1,937,857		194		13,371			-			13,565

Conversion of notes payable and interest to common stock		-		-		3,247,515		325		1,125,840			-			1,126,165

Vendor liability settled in stock		-		-		500,000		50		3,450						3,500

Proceeds from subscriptions payable, net		-		-		-		-		5,040			-			5,040

Stock issued for services		-		-		300,000		30		74,970			-			75,000

Employee stock options issued		-		-		-		-		114,083			-			114,083

Net loss, June 30, 2012													(1,117,904	)		(1,117,904	)

Balance, June 30, 2012		100	$	19		64,645,100	$	6,465	$	4,983,482		$	(2,102,463	)	$	2,887,503

See accompanying notes to financial statements

F-27

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Statements of Cash Flows

							January 25, 2011
							(Date of Inception)
							through
	For the six months ended June 30,						June 30,
	2012			2011			2012
	(unaudited)			(unaudited)			(unaudited)
Cash Flows From Operating Activities:
Net loss	$	(1,117,904	)	$	(268,316	)	$	(2,102,463	)
Adjustments to reconcile net loss to net cash used in operating activities
Depletion, depreciation and amortization		167,662			-			278,455
Stock based compensation		383,260			-			458,260
Amortization of debt issue costs		22,102			-			32,144
Accretion of debt discount		299,380			-			437,042
Change in fair value of derivative liabilities		(12,591	)		-			(11,889	)
Changes in operating assets and liabilities:
(Increase) decrease in:
Accounts receivable		(33,278	)		-			(61,614	)
Prepaid expenses		(3,429	)		-			(5,229	)
Inventory		4,070			(48,797	)		(39,119	)
Increase (decrease) in:
Accounts payable and accrued liabilities		160,831			44,268			282,720
Net Cash Used In Operating Activities		(129,897	)		(272,846	)		(731,693	)

Cash Flows From Investing Activities:
Purchase of oil and gas properties		(553,134	)		(685,618	)		(3,434,316	)
Deposit on property		-			-			(10,000	)
Purchase of furniture and equipment		-			-			(1,626	)
Net Cash Used In Investing Activities		(553,134	)		(685,618	)		(3,445,942	)

Cash Flows From Financing Activities:
Proceeds from notes payable		60,000			845,000			2,195,000
Repayments on notes payable		(100,000	)		(230,000	)		(330,000	)
Debt issuance costs paid in cash		-			-			(34,500	)
Sale of common stock for cash		481,250			1,003,900			2,716,859
Proceeds from subscriptions payable		100,000			170,495			100,000
Proceeds from stock subscriptions receivable		15,400			-			15,400
Repayment of stock subscriptions		(28,315	)		-			(28,315	)
Stock issuance costs paid in cash		-			-			(25,700	)
Net Cash Provided By Financing Activities		528,335			1,789,395			4,608,744

Net change in cash		(154,696	)		830,931			431,109

Cash at beginning of period		585,805			-			-

Cash at end of period	$	431,109		$	830,931		$	431,109

Supplemental disclosures of cash flow information:
Cash paid for interest	$	3,918		$	-		$	8,143
Cash paid for taxes	$	-		$	-		$	-

Supplemental disclosure of non-cash investing and financing activities:

Conversion of notes payable and accrued interest to common stock	$	1,126,165		$	-		$	1,745,312
Vendor liability settled in stock	$	3,500
Issuance of common stock for a subscription receivable	$	12,065		$	-		$	27,465
Purchase of property for common stock	$	-		$	-		$	18,750
Original issue discount on notes payable	$	-		$	-		$	138,000
Derivative liability recorded to debt discount at issuance of notes payable	$	17,783		$	-		$	334,005

See accompanying notes to financial statements

F-28

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Notes to Financial Statements (unaudited)

June 30, 2012

Note 1 Nature of Operations and Basis of Presentation:

Nature of Operations

The Company’s major assets are an oil well in Roosevelt County, Montana and leaseholds affording drilling rights in North Dakota, Montana, Kansas, Nebraska and Colorado.

Basis of Presentation

The accompanying unaudited interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and the rules and regulations of the United States Securities and Exchange Commission for interim financial information.

Certain information or footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted, pursuant to the rules and regulations of the Securities and Exchange Commission for interim financial reporting. Accordingly, they do not include all the information and footnotes necessary for a comprehensive presentation of financial position, results of operations, or cash flows. It is management's opinion, however, that all material adjustments (consisting of normal recurring adjustments) have been made which are necessary for a fair financial statement presentation. The interim results for the six months ended June 30, 2012 are not necessarily indicative of results for the full fiscal year.

Development Stage Company

The Company is a development stage company since it has not yet generated substantial revenue from the sale of oil and gas and, through June 30, 2012, its efforts have been principally devoted to the regulatory, legal and research requirements for the development of a portfolio of proven oil and gas reserves. The accompanying financial statements have been prepared in accordance with the provisions of Financial Accounting Standards Board Accounting Standards Codification (FASB ASC) 915-205-45.

Note 2 Summary of Significant Accounting Policies:

Use of Estimates

F-29

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

The accompanying financial statements contain estimates of the Company’s proved reserves and the estimated future net revenues from the proved reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Risks and Uncertainties

Cash and Cash Equivalents

The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. There were no cash equivalents at June 30, 2012 and December 31, 2011.

The Company minimizes its credit risk associated with cash by periodically evaluating the credit quality of its primary financial institution.

F-30

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable consist primarily of oil and gas receivables, net of a valuation allowance for doubtful accounts. As of June 30, 2012 and December 31, 2011, the allowance for doubtful accounts was $0.

Inventories

Inventories are stated at the lower of cost or market using the first-in, first-out (FIFO) valuation method.

	June 30, 2012		December 31, 2011

Finished goods	$	39,119	$	43,189
Reserve		-		-
	$	39,119	$	43,189

Oil and Gas Properties, Successful Efforts Method

Support Facilities and Equipment

Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.

Proved Reserves

Estimates of the Company’s proved reserves included in this report are prepared in accordance with GAAP and guidelines from the United States Securities and Exchange Commission (“SEC”). The Company’s engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and impairment. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of the Company’s estimated proved reserves. The Company engages independent reserve engineers to estimate its proved reserves.

F-31

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

Asset Retirement Obligations

The Company follows the provisions of the Accounting Standards Codification ASC 410 - Asset Retirement and Environmental Obligations. The fair value of an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. As of June 30, 2012 and December 31, 2011, the Company’s obligations were immaterial. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. The Company’s asset retirement obligations relate to the abandonment of oil and gas producing facilities. The amounts recognized are based upon numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and gas, future inflation rates and the credit-adjusted risk-free interest rate.

Debt Issue Costs and Debt Discount

Original Issue Discount

For certain convertible debt issued in 2012 and 2011, the Company provided the debt holder with an original issue discount. The original issue discount was equal to simple interest at 10% - 20% of the proceeds raised. The original issue discount was recorded to debt discount reducing the face amount of the note and is being amortized to interest expense over the maturity period of the debt.

Derivative Financial Instruments

Revenue Recognition

Revenues from the sale of oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company follows the “sales method” of accounting for oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than its share of the expected remaining proved reserves.

F-32

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

Share-Based Payments

Income Taxes

Earnings Per Share

The Company had the following potential common stock equivalents at June 30, 2012:

Convertible debt – face amount of $300,000, conversion price of $0.35			857,142
Common stock options, exercise price of $0.25			6,000,000
Common stock warrants, exercise price of $0.35			1,350,000
Total common stock equivalents			8,207,142

The Company had no potential common stock equivalents at June 30, 2011.

Since the Company reflected a net loss in 2012 and 2011, the effect of considering any common stock equivalents, would have been anti-dilutive. A separate computation of diluted earnings (loss) per share is not presented.

F-33

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

Fair Value of Financial Instruments

Level 1		Quoted market prices available in active markets for identical assets or liabilities as of the reporting date.

Level 2		Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3		Pricing inputs that are generally unobservable inputs and not corroborated by market data.

The Company’s Level 3 financial liabilities consist of the derivative warrant issued with the 2011 and 2012 notes payables for which there is no current market for this security such that the determination of fair value requires significant judgment or estimation. The Company valued the reset adjustments in the warrant on subsequent potential equity offerings using an option pricing model, for which management understands the methodologies. These models incorporate transaction details such as the Company’s stock price, contractual terms, maturity, risk-free rates, as well as assumptions about future financings, volatility, and holder behavior as of the date of issuance and each balance sheet date.

Fair Value of Financial Assets and Liabilities Measured on a Recurring Basis

F-34

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

Financial assets and liabilities measured at fair value on a recurring basis are summarized below and disclosed on the balance sheets as follows:

June 30, 2012	Fair Value Measurement Using

	Level 1		Level 2		Level 3		Total

Derivative warrant liabilities	$	-	$	-	$	322,116	$	322,116

December 31, 2011	Fair Value Measurement Using

	Level 1		Level 2		Level 3		Total

Derivative warrant liabilities	$	-	$	-	$	316,924	$	316,924

	Fair Value Measurement Using Level 3 Inputs
	Derivative Liabilities		Total

Balance, January 25, 2011 (Date of Inception)	$	-	$	-

Purchases, issuances and settlements		316,222		316,222

Total gains or losses (realized/unrealized) included in net loss		702		702

Transfers in and/or out of Level 3		-		-

Balance, December 31, 2011	$	316,924	$	316,924

Purchases, issuances and settlements		17,783		17,783

Total gains or losses (realized/unrealized) included in net loss		(12,591		(12,591


Transfers in and/or out of Level 3		-		-

Balance, June 30, 2012	$	322,116	$	322,116

F-35

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

Recent Accounting Pronouncements

Note 3 Going Concern:

As reflected in the accompanying unaudited financial statements, the Company has a net loss of $1,117,904 and net cash used in operations of $129,897 for the six months ended June 30, 2012; and has a working capital deficit of $298,734.

Note 4 Oil and Gas Assets:

The following table summarizes the Company’s oil and gas assets:

Cost January 25, 2011 (Date of Inception)	$	-
Additions		2,765,232
Depletion		(103,968	)
Impairment		-
Balance – December 31, 2011		2,661,264
Additions		553,134
Depletion		(160,656	)
Impairment		-
Balance – June 30, 2012	$	3,053,742

F-36

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

Cost January 25, 2011 (Date of Inception)	$	-
Additions		134,700
Depletion		(6,735	)
Impairment		-
Balance – December 31, 2011		127,965
Additions		-
Depletion		(6,735	)
Impairment		-
Balance – June 30, 2012	$	121,230

During the six months ended June 30, 2012 and 2011, the Company recorded $167,391 and $0 to depletion expense.

Note 5 Furniture and Equipment:

The following table summarizes furniture and equipment:

Cost January 25, 2011 (Date of Inception)	$	-
Additions		1,626
Depreciation		(90	)
Impairment		-
Balance – December 31, 2011		1,536
Additions		-
Depreciation		(271	)
Impairment		-
Balance – June 30, 2012	$	1,265

During the six months ended June 30, 2012 and 2011, the Company recorded $271 and $0, respectively to depreciation expense.

Note 6 Notes Payable:

(A) Notes Payable – 10%

During the period ended December 31, 2011, sixteen (16) note-holders converted $615,000 in notes payable and $4,147 of accrued interest into 2,476,585 shares of the Company’s common stock at a conversion rate of $0.25/share.

During the period ended December 31, 2011, three (3) note-holders were re-paid $230,000 in principal.

F-37

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

The following is a summary of notes payable – related parties:

Balance – January 25, 2011 (Date of Inception)	$	-
Issuance of notes payable		845,000
Repayments		(230,000	)
Converted to common stock		(615,000	)
Balance – December 31, 2011	$	-

Notes Payable – Convertible

During the period ended December 31, 2011, the Company sold four (4) convertible promissory notes in the aggregate principal amount of $328,000 for proceeds of $300,000 with a one year maturity and a 5 year common stock purchase warrant exercisable for up to 290,000 shares of common stock at $0.35 per share to an accredited investor. The notes are convertible at a rate of $0.35 per share. The notes are unsecured.

During the six months ended June 30, 2012, the Company sold two (2) convertible promissory notes in the aggregate principal amount of $72,000 for proceeds of $60,000 with a one year maturity and a 5 year common stock purchase warrant exercisable for up to 60,000 shares of common stock at $0.35 per share to an accredited investor. The notes are convertible at a rate of $0.35 per share. The notes are unsecured.

The following is a summary of notes payable - convertible:

Balance – January 25, 2011 (Date of Inception)	$	-
Issuance of convertible notes payable		1,428,000
Original issue discount		(138,000
Discount recorded on derivative liability at issuance		(316,222
Repayments		-
Converted to common stock		-
Accretion of debt discount		137,662
Balance – December 31, 2011		1,111,440
Issuance of convertible notes payable		72,000
Original issue discount		(12,000
Discount recorded on derivative liability at issuance		(17,783
Repayments		(100,000
Converted to common stock		(1,100,000
Accretion of debt discount		299,380
Balance – June 30, 2012	$	253,037

F-38

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

Debt issuance costs, net are as follows:

Balance – January 25, 2011 (Date of Inception)	$	-
Debt issue costs paid in 2011		34,500
Amortization of debt issue costs		(10,042	)
Balance – December 31, 2011		24,458
Debt issue costs paid in 2012		-
Amortization of debt issue costs		(22,102	)
Balance – June 30, 2012	$	2,356

Note 7 Stockholders’ Equity:

(A)	Preferred Stock

During the six months ended June 30, 2012, the Company issued the following preferred stock:

Transaction Type	Quantity of Shares		Valuation		Range of Value per Share
Services rendered – officers		100	$	194,158	$	1,942
Total		100	$	194,158	$	1,942

(B)	Common Stock

During the six months ended June 30, 2012, the Company issued the following common stock:

Transaction Type	Quantity of Shares		Valuation		Range of Value per Share
Issued for cash		5,707,143	$	520,230	$	0.007 - $0.35
Issued for subscription receivable		1,937,857	$	13,565	$	0.007
Conversion of debt and interest		3,247,515	$	1,126,165	$	0.25 - 0.35
Vendor liability settled in stock		500,000	$	3,500	$	0.007
Services rendered – consultants		300,000	$	75,000	$	0.25
Total		11,692,515	$	1,738,460	$	0.007 - $0.35

During the period January 25, 2011 (Date of Inception) to June 30, 2012, the Company issued the following common stock:

Transaction Type	Quantity of Shares		Valuation		Range of Value per Share
Founder shares		10,500,000	$	-	$	-
Issued for cash		43,048,143	$	2,755,839	$	0.007 - $0.35
Issued for subscription receivable		4,137,857	$	28,965	$	0.007
Issued for purchase of property		75,000	$	18,750	$	0.25
Services rendered – consultants		660,000	$	150,000	$	0.007 - $0.25
Vendor liability settled in stock		500,000	$	3,500	$	0.007
Conversion of debt and interest		5,724,100	$	1,745,312	$	0.25 - 0.35
Total		64,645,100	$	4,702,366	$	0.007 - $0.35

F-39

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

The following is a summary of the Company’s warrant activity:

	Warrants		Weighted Average Exercise Price

Outstanding – January 25, 2011 (Date of Inception)		-	$	-
Exercisable – January 25, 2011 (Date of Inception)		-	$	-
Granted		1,290,000	$	0.35
Exercised		-	$	-
Forfeited/Cancelled		-	$	-
Outstanding – December 31, 2011		1,290,000	$	0.35
Exercisable – December 31, 2011		1,290,000	$	0.35
Granted		60,000	$	0.35
Exercised		-	$	-
Forfeited/Cancelled		-	$	-
Outstanding – June 30, 2012		1,350,000	$	0.35
Exercisable – June 30, 2012		1,350,000	$	0.35

Warrants Outstanding

Warrants Exercisable

Range of Range of

exercise price Number

Outstanding

Number Outstanding

Weighted Average Remaining Contractual Life

(in years)

Weighted Average

Remaining Contractual

Life (in years)

Weighted Average

Exercise Price

Weighted Average Exercise Price

Number Exercisable

Weighted Average Exercise Price

$0.35

1,350,000

4.39 years

$0.35

1,350,000

$0.35

At June 30, 2012 and December 31, 2011, the total intrinsic value of warrants outstanding and exercisable was $0.

F-40

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

(D) Options

The following is a summary of the Company’s option activity:

	Options		Weighted Average Exercise Price

Outstanding – January 25, 2011 (Date of Inception)		-	$	-
Exercisable – January 25, 2011 (Date of Inception)		-	$	-
Granted		-	$	-
Exercised		-	$	-
Forfeited/Cancelled		-	$	-
Outstanding – December 31, 2011		-	$	-
Exercisable – December 31, 2011		-	$	-
Granted		6,000,000	$	0.25
Exercised		-	$	-
Forfeited/Cancelled		-	$	-
Outstanding – June 30, 2012		6,000,000	$	0.25
Exercisable – June 30, 2012		500,000	$	0.25

Options Outstanding

Options Exercisable

Range of Range of

exercise price Number

Outstanding

Number Outstanding

Weighted Average Remaining Contractual Life

(in years)

Weighted Average

Remaining Contractual

Life (in years)

Weighted Average

Exercise Price

Weighted Average Exercise Price

Number Exercisable

Weighted Average Exercise Price

$0.25

6,000,000

2.75 years

$0.25

500,000

$0.25

At June 30, 2012 and December 31, 2011, the total intrinsic value of options outstanding and exercisable was $0.

Note 8 Commitments and Contingencies:

Litigations, Claims and Assessments

From time to time, the Company may become involved in various lawsuits and legal proceedings, which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm its business. The Company is currently not aware of any such legal proceedings or claims that they believe will have, individually or in the aggregate, a material adverse affect on its business, financial condition or operating results.

On May 18, 2012, Stratex filed a complaint against Petrogulf Corporation in the U.S. District Court for the District of North Dakota alleging breach of an agreement to assign to Stratex a non-operating, working interest in certain oil wells and oil & gas leases. Stratex seeks specific performance of the disputed agreement, an award of compensatory damages to be determined at trial, but in no event less than $50 million, plus interest, costs incurred in connection with this litigation and such relief as the court may deem proper. Petrogulf Corporation seeks declaratory judgment and monetary damages related to and arising from our complaint filing.

Oil and Gas Prices

F-41

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

Environmental Liabilities

Employment Contracts

On April 1, 2012, the Company entered into an Executive Employment Agreement with the Chief Executive Officer. The terms of the Agreement are as follows:

●	Term - 5 years,

●	Compensation - $250,000 salary per annum, bonus eligibility, (annual raises equal to 10%),

●	Option Grant - 3,000,000 options to acquire restricted stock,

●	Preferred Share Grant - 50 shares of Preferred Stock which entitle the CEO to 50 million votes on all matters submitted to a vote of the shareholders of the Company.

On April 1, 2012, the Company entered into an Executive Employment Agreement with the Chief Operating Officer. The terms of the Agreement are as follows:

●	Term - 5 years,

●	Compensation - $250,000 salary per annum, bonus eligibility, (annual raises equal to 10%),

●	Option Grant - 3,000,000 options to acquire restricted stock,

●	Preferred Share Grant - 50 shares of Preferred Stock which entitle the COO to 50 million votes on all matters submitted to a vote of the shareholders of the Company.

Note 9 Subsequent Events:

The Company has evaluated for any subsequent events through October 15, 2012, which is the date these financial statements were available to be issued.

On July 6, 2012 (the “Closing Date”), Stratex Acquisition Corp. (“Acquisition Corp.”), a wholly-owned subsidiary of Pubco, merged (the “Merger”) with and into Stratex Oil & Gas, Inc., a Delaware corporation (“Stratex”). Stratex was the surviving corporation of that Merger. As a result of the Merger, Pubco acquired the business of Stratex, and will continue the existing business operations of Stratex as a wholly-owned subsidiary, in a transaction treated as a reverse acquisition. Pubco had minimal operations and majority-voting control was transferred to Stratex. The transaction also requires a recapitalization of Stratex. Since Stratex acquired a controlling voting interest, it was deemed the accounting acquirer, while Pubco was deemed the legal acquirer. The historical financial statements of the Company are those of Stratex, and of the consolidated entities from the date of merger and subsequent.

F-42

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Financial Statements (unaudited)

June 30, 2012

Simultaneously with the Merger, on the Closing Date all of the issued and outstanding shares of Stratex common stock converted, on a 2 for 1 basis, into shares of the Company’s common stock, (“Common Stock”). Also on the Closing Date, all of the issued and outstanding options to purchase shares of Stratex common stock, and all of the issued and outstanding warrants (collectively the “Stratex Convertible Securities”) to purchase shares of Stratex Common Stock, upon the exercise or conversion of the Stratex Convertible Securities, shall have the right to convert such Stratex Convertible Securities into the kind and amount of the Company’s shares of Common Stock and other securities and property which such holder would have owned or have been entitled to receive of Stratex prior to the Closing of the Merger, on a 2 for 1 basis. The options will be administered under Stratex’s 2012 Equity Incentive Plan (the “Stratex Plan”), which the Company assumed and adopted on the Closing Date in connection with the Merger.

Subsequent to the balance sheet date, the Company issued common shares for cash totaling approximately $300,000

F-43

STRATEX OIL & GAS, INC.

(A DEVELOPMENT STAGE COMPANY)

FINANCIAL STATEMENTS (UNAUDITED)

FOR THE PERIOD JANUARY 25, 2011 (DATE OF INCEPTION) TO MARCH 31, 2012

	Page(s)

Balance Sheets – March 31, 2012 (unaudited) and December 31, 2011	F-45

Statements of Operations – For the three months ended March 31, 2012 and 2011 (unaudited) and for the period January 25, 2011 (Date of Inception) to March 31, 2012 (unaudited)	F-46

Statement of Stockholders’ Equity - Period January 25, 2011 (Date of Inception) to March 31, 2012 (unaudited)	F-47

Statements of Cash Flows – For the three months ended March 31, 2012 and 2011 (unaudited) and for the period January 25, 2011 (Date of Inception) to March 31, 2012 (unaudited)	F-48

Notes to Financial Statements	F-49 to F-61

F-44

Stratex Oil & Gas, Inc.
(A Development Stage Company)
Balance Sheets

	March 31, 2012			December 31, 2011
	(unaudited)
Assets

Current Assets:
Cash	$	105,458		$	585,805
Accounts receivable, net		52,766			28,336
Inventory		39,119			43,189
Subscriptions receivable		15,400			15,400
Prepaid expenses		25,200			1,800
Debt issuance costs		8,697			24,458
Total Current Assets		246,640			698,988

Deposits		10,000			10,000
Oil and gas property, plant and equipment:
Proven property - net		566,880			595,547
Unproven property		2,663,361			2,193,682
Furniture and equipment		1,400			1,536
Total Assets	$	3,488,281		$	3,499,753

Liabilities and Stockholders' Equity

Current Liabilities:
Accounts payable and accrued liabilities	$	28,342		$	117,742
Notes payable, net of debt discount		1,265,596			1,111,440
Derivative liability - warrants		329,654			316,924
Total Current Liabilities		1,623,592			1,546,106


Total Liabilities		1,623,592			1,546,106

Stockholders' Equity:
Series A, convertible preferred stock, $0.0001 par value; 100
shares authorized, none issued and outstanding		-			-
Common stock, $0.0001 par value; 125,000,000 shares authorized;
and 54,352,585 and 52,952,585 shares issued and outstanding		5,435			5,295
Additional paid in capital		3,265,271			2,932,911
Deficit accumulated during the development stage		(1,406,017	)		(984,559	)
Total Stockholders' Equity		1,864,689			1,953,647

Total Liabilities and Stockholders' Equity	$	3,488,281		$	3,499,753

F-45

Stratex Oil & Gas, Inc.
(A Development Stage Company)
Statements of Operation


							January 25, 2011
	For the three months						(Date of Inception)
	ended March 31,						through
	2012			2011			2012
	(unaudited)			(unaudited)			(unaudited)

Revenue	$	220,211		$	-		$	460,333

Operating expenses:
Production expenses		68,304			-			169,569
Depletion, depreciation and amortization		67,203			-			177,996
General and administrative		281,583			29,360			1,109,812
Total operating expenses		417,090			29,360			1,457,377

Loss from operations		(196,879	)		(29,360	)		(997,044	)

Other Income and Expense:
Interest income		534			-			534
Interest expense		(230,166	)		(2,601	)		(413,858	)
Change in fair value - derivative liabilities		5,053			-			4,351
Total other income and expense		(224,579	)		(2,601	)		(408,973	)


Net loss	$	(421,458	)	$	(31,961	)	$	(1,406,017	)

Net loss per common share - basic and diluted	$	(0.01	)	$	(0.00	)

Weighted average common shares outstanding
- basic and diluted		53,708,629			9,500,000

F-46

Stratex Oil & Gas, Inc.
(A Development Stage Company)
Statement of Stockholders' Equity (unaudited)
For the Period from January 25, 2011 (Date of Inception) to March 31, 2012

								Deficit
								Accumulated
	Common Stock				Additional			during the
	Shares		Amount		Paid-In Capital			Development Stage			Stockholders' Equity

Balance, January 25, 2011 (Date of Inception)		-		-		-			-			-

Common stock issued to founders		10,500,000		1,050		(1,050	)		-			-

Common stock issued for cash ($0.007/share - $0.25/share)		37,341,000		3,734		2,231,875			-			2,235,609

Common stock issued for subscription receivable ($0.007/share)		2,200,000		220		15,180			-			15,400

Common stock issued for property		75,000		7		18,743			-			18,750

Conversion of notes payable and interest to common stock		2,476,585		248		618,899			-			619,147

Stock issued for services		360,000		36		74,964			-			75,000

Stock issuance costs		-		-		(25,700	)		-			(25,700	)

Net loss, December 31, 2011									(984,559	)		(984,559	)

Balance, December 31, 2011		52,952,585	$	5,295	$	2,932,911		$	(984,559	)	$	1,953,647

Common stock issued for cash ($0.007/share - $0.25/share)		1,100,000		110		123,370			-			123,480

Proceeds from subscriptions payable		-		-		134,020			-			134,020

Stock issued for services		300,000		30		74,970			-			75,000

Net loss, March 31, 2012								$	(421,458	)		(421,458	)

Balance, March 31, 2012	$	54,352,585	$	5,435	$	3,265,271		$	(1,406,017	)	$	1,864,689

F-47

Stratex Oil & Gas, Inc.
(A Development Stage Company)
Statements of Cash Flows


							January 25, 2011
							(Date of Inception)
	For the three months						through
	ended March 31,						March 31,
	2012			2011			2012
	(unaudited)			(unaudited)			(unaudited)
Cash Flows From Operating Activities:
Net loss	$	(421,458	)	$	(31,961	)	$	(1,406,017	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization		67,203			-			177,996
Stock based compensation		75,000			-			150,000
Amortization of debt issue costs		15,761			-			25,803
Accretion of debt discount		211,939			-			349,601
Change in fair value of derivative liabilities		(5,053	)		-			(4,351	)
Changes in operating assets and liabilities:
(Increase) decrease in:
Accounts receivable		(24,430	)		-			(52,766	)
Prepaid expenses		(23,400	)		-			(25,200	)
Inventory		4,070			-			(39,119	)
Increase (decrease) in:
Accounts payable and accrued liabilities		(89,400	)		55,739			32,489
Net Cash Provided by (Used in) Operating Activities		(189,768	)		23,778			(791,564	)

Cash Flows From Investing Activities:
Purchase of oil and gas properties		(508,079	)		(439,438	)		(3,389,261	)
Deposit on property		-			-			(10,000	)
Purchase of furniture and equipment		-			-			(1,626	)
Net Cash Used In Investing Activities		(508,079	)		(439,438	)		(3,400,887	)

Cash Flows From Financing Activities:
Proceeds from notes payable		60,000			385,000			2,195,000
Repayments on notes payable		(100,000	)		-			(330,000	)
Debt issuance costs paid in cash		-			-			(34,500	)
Sale of common stock for cash		123,480			30,940			2,359,089
Proceeds from subscriptions payable		134,020			-			134,020
Stock issuance costs paid in cash		-			-			(25,700	)
Net Cash Provided By Financing Activities		217,500			415,940			4,297,909

Net change in cash		(480,347	)		280			105,458

Cash at beginning of period		585,805			-			-

Cash at end of period	$	105,458		$	280		$	105,458

Supplemental disclosures of cash flow information:
Cash paid for interest	$	3,918		$	-		$	8,143
Cash paid for taxes	$	-		$	-		$	-

Supplemental disclosure of non-cash investing and financing activities:

Conversion of notes payable and accrued interest to common stock	$	-		$	-		$	619,147
Issuance of common stock for a subscription receivable	$	-		$	-		$	15,400
Purchase of property for common stock	$	-		$	-		$	18,750
Original issue discount on notes payable	$	12,000		$	-		$	150,000
Derivative liability recorded to debt discount at issuance of notes payable	$	17,783		$	-		$	334,005

F-48

Stratex Oil & Gas, Inc.

(A Development Stage Company)

Notes to Financial Statements (unaudited)

March 31, 2012

Note 1

Nature of Operations and Basis of Presentation

Nature of Operations

The Company’s major assets are an oil well in Roosevelt County, Montana and leaseholds affording drilling rights in North Dakota, Montana, Kansas, Nebraska and Colorado.

Development Stage Company

The Company is a development stage company since it has not yet generated substantial revenue from the sale of oil and gas and, through March 31, 2012, its efforts have been principally devoted to the regulatory, legal and research requirements for the development of a portfolio of proven oil and gas reserves. The accompanying financial statements have been prepared in accordance with the provisions of Financial Accounting Standards Board Accounting Standards Codification (FASB ASC) 915-205-45.

Note 2

Summary of Significant Accounting Policies

Use of estimates

The accompanying financial statements contain estimates of the Company’s proved reserves and the estimated future net revenues from the proved reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

F-49

Risks and uncertainties

Cash and cash equivalents

The Company considers all highly liquid instruments purchased with a maturity of three months or less to be cash equivalents. There were no cash equivalents at March 31, 2012 and December 31, 2011.

The Company minimizes its credit risk associated with cash by periodically evaluating the credit quality of its primary financial institution.

Accounts receivable and allowance for doubtful accounts

Accounts receivable consist primarily of oil and gas receivables, net of a valuation allowance for doubtful accounts. As of March 31, 2012 and December 31, 2011, the allowance for doubtful accounts was $0 and $0, respectively.

Inventories

Inventories are stated at the lower of cost or market using the first-in, first-out (FIFO) valuation method.

F-50

	March 31, 2012			December 31, 2011
Finished goods	$	39,119		$	43,189
Reserve		(-	)		(-	)
	$	39,119		$	43,189

Oil and Gas Properties, Successful Efforts Method

Support Facilities and Equipment

Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.

Proved Reserves

Estimates of the Company’s proved reserves included in this report are prepared in accordance with GAAP and guidelines from the United States Securities and Exchange Commission (“SEC”). The Company’s engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and impairment. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions, and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of the Company’s estimated proved reserves. The Company engages independent reserve engineers to estimate its proved reserves.

Asset Retirement Obligations

The Company follows the provisions of the Accounting Standards Codification ASC 410 - Asset Retirement and Environmental Obligations. The fair value of an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. As of March 31, 2012 and December 31, 2011, the Company’s obligations were immaterial. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. The Company’s asset retirement obligations relate to the abandonment of oil and gas producing facilities. The amounts recognized are based upon numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and gas, future inflation rates and the credit-adjusted risk-free interest rate.

F-51

Debt Issue Costs and Debt Discount

Original Issue Discount

For certain convertible debt issued in 2012 and 2011, the Company provided the debt holder with an original issue discount. The original issue discount was equal to simple interest at 10% -20% of the proceeds raised. The original issue discount was recorded to debt discount reducing the face amount of the note and is being amortized to interest expense over the maturity period of the debt.

Derivative Financial Instruments

Revenue recognition

Revenues from the sale of oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company follows the “sales method” of accounting for oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than its share of the expected remaining proved reserves.

Share-based payments

Income Taxes

F-52

Earnings per share

The Company had the following potential common stock equivalents at March 31, 2012:


Convertible debt – face amount of $1,400,000, conversion price of $0.35			4,000,000
Common stock warrants, exercise price of $0.35			1,362,000
Total common stock equivalents			5,362,000

The Company had no potential common stock equivalents at March 31, 2011.

Fair Value of Financial Instruments

Level 1		Quoted market prices available in active markets for identical assets or liabilities as of the reporting date.

Level 2		Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3		Pricing inputs that are generally observable inputs and not corroborated by market data.

F-53

Fair Value of Financial Assets and Liabilities Measured on a Recurring Basis

Financial assets and liabilities measured at fair value on a recurring basis are summarized below and disclosed on the balance sheets as follows:

March 31, 2012	Fair Value Measurement Using

	Level 1		Level 2		Level 3		Total
Derivative warrant liabilities	$	-	$	-	$	329,654	$	329,654
December 31, 2011	Fair Value Measurement Using

	Level 1		Level 2		Level 3		Total
Derivative warrant liabilities	$	-	$	-	$	316,924	$	316,924

F-54

	Fair Value Measurement Using Level 3 Inputs
	Derivative Liabilities				Total
Balance, January 25, 2011 (Date of Inception)		$	-		$	-

Purchases, issuances and settlements			316,222			316,222

Total gains or losses (realized/unrealized)
included in net loss			702			702

Transfers in and/or out of Level 3			-			-

Balance, December 31, 2011		$	316,924		$	316,924

Purchases, issuances and settlements			17,783			17,783

Total gains or losses (realized/unrealized)			(5,053	)		(5,053	)
included in net loss

Transfers in and/or out of Level 3			-			-

Balance, March 31, 2012		$	329,654		$	329,654

Recent accounting pronouncements

In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. The guidance in ASU 2011-04 changes the wording used to describe the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements, including clarification of the FASB's intent about the application of existing fair value and disclosure requirements and changing a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The amendments in this ASU should be applied prospectively and are effective for interim and annual periods beginning after December 15, 2011. Early adoption by public entities is not permitted. The adoption of this guidance is not expected to have a material impact on the Company’s financial position or results of operations.

Note 3 Going Concern

As reflected in the accompanying unaudited financial statements, the Company has a net loss of $421,458 and net cash used in operations of $189,768 for the three months ended March 31, 2012; and has a working capital deficit of $1,376,952.

F-55

Note 4 Oil and Gas Assets:

The following table summarizes the oil and gas assets:

Cost January 25, 2011 (Date of Inception)	$	-
Additions		2,765,232
Depletion		(103,968	)
Impairment		-
Balance – December 31, 2011		2,661,264
Additions		508,079
Depletion		(63,699	)
Impairment		-
Balance – March 31, 2012	$	3,105,644

Cost January 25, 2011 (Date of Inception)	$	-
Additions		134,700
Depletion		(6,735	)
Impairment		-
Balance – December 31, 2011		127,965
Additions		-
Depletion		(3,368	)
Impairment		-
Balance – March 31, 2012	$	124,597

During the period ended March 31, 2012 and 2011, the Company recorded $67,098 and $0 to depletion expense.

F-56

Note 5 Furniture and Equipment:

The following table summarizes furniture and equipment:

Cost January 25, 2011 (Date of Inception)	$	-
Additions		1,626
Depreciation		(90	)
Impairment		-
Balance – December 31, 2011		1,536
Additions		-
Depreciation		(136	)
Impairment		-
Balance – March 31, 2012	$	1,400

During the periods ended March 31, 2012 and 2011, the Company recorded $136 and $0, respectively to depreciation expense.

Note 6 Notes Payable

(A)	Notes Payable – 10%

During the period ended December 31, 2011, three (3) noteholders were re-paid $230,000 in principal.

The following is a summary of notes payable – related parties:

Balance – January 25, 2011 (Date of Inception)	$	-
Issuance of notes payable		845,000
Repayments		(230,000	)
Converted to common stock		(615,000	)
Balance – December 31, 2011	$	-

(B)	Notes Payable – Convertible

On October 19, 2011, the Company sold a convertible promissory note in the aggregate principal amount of $1,100,000 for proceeds of $1,000,000 payable May 24, 2012 and a 5 year common stock purchase warrant exercisable for up to 1,000,000 shares of common stock at $0.35 per shares to an accredited investor. The note is convertible at a rate of $0.35 per share. The note is unsecured.

F-57

During the period ended December 31, 2011, the Company sold 4 convertible promissory notes in the aggregate principal amount of $328,000 for proceeds of $300,000 with a one year maturity and a 5 year common stock purchase warrant exercisable for up to 290,000 shares of common stock at $0.35 per shares to an accredited investor. The notes are convertible at a rate of $0.35 per share. The notes are unsecured.

During the three months ended March 31, 2012, the Company sold two (2) convertible promissory notes in the aggregate principal amount of $72,000 for proceeds of $60,000 with a one year maturity and a 5 year common stock purchase warrant exercisable for up to 72,000 shares of common stock at $0.35 per shares to an accredited investor. The notes are convertible at a rate of $0.35 per share. The notes are unsecured.

The following is a summary of notes payable - convertible:

Balance – January 25, 2011 (Date of Inception)	$	-
Issuance of convertible notes payable		1,428,000
Original issue discount		(138,000	)
Discount recorded on derivative liability at issuance		(316,222	)
Repayments		(-	)
Converted to common stock		(-	)
Accretion of debt discount		137,662
Balance – December 31, 2011		1,111,440
Issuance of convertible notes payable		72,000
Original issue discount		(12,000	)
Discount recorded on derivative liability at issuance		(17,783	)
Repayments		(100,000	)
Converted to common stock		(-	)
Accretion of debt discount		211,939
Balance – March 31, 2012	$	1,265,596

Debt issuance costs, net are as follows:

Balance – January 25, 2011 (Date of Inception)	$	-
Debt issue costs paid in 2011		34,500
Amortization of debt issue costs		(10,042	)
Balance - December 31, 2011		24,458
Debt issue costs paid in 2012		-
Amortization of debt issue costs		(15,761	)
Balance – March 31, 2012	$	8,697

Note 7 Stockholders Equity

(A)	Common Stock

During the three months ended March 31, 2012, the Company issued the following common stock:

Transaction Type	Quantity of Shares		Valuation		Range of Value per Share
Issued for cash		1,100,000	$	123,480	$	0.007 - $0.25
Services rendered – consultants		300,000	$	75,000	$	0.25

Total		1,400,000	$	198,480	$	0.007 - $0.25

F-58

During the period January 25, 2011 (Date of Inception) to March 31, 2012, the Company issued the following common stock:

Transaction Type	Quantity of Shares		Valuation		Range of Value per Share
Founder shares		10,500,000	$	-	$	-
Issued for cash		38,441,000	$	2,359,089	$	0.007 - $0.25
Issued for subscription receivable		2,200,000	$	15,400	$	0.007
Issued for purchase of property		75,000	$	18,750	$	0.25
Services rendered – consultants		660,000	$	150,000	$	0.007 - $0.25
Conversion of debt and interest		2,476,585	$	619,147	$	0.25

Total		54,352,585	$	3,162,386	$	0.007 - $0.25

The following is a summary of the Company’s warrant activity:

	Warrants		Weighted Average Exercise Price
Outstanding – January 25, 2011 (Date of Inception)		-	$	-
Exercisable – January 25, 2011 (Date of Inception)		-	$	-
Granted		1,290,000	$	0.35
Exercised		-	$	-
Forfeited/Cancelled		-	$	-
Outstanding – December 31, 2011		1,290,000	$	0.35
Exercisable – December 31, 2011		1,290,000	$	0.35
Granted		72,000	$	0.35
Exercised		-	$	-
Forfeited/Cancelled		-	$	-
Outstanding – March 31, 2012		1,362,000	$	0.35
Exercisable – March 31, 2012		1,362,000	$	0.35

Warrants Outstanding							Warrants Exercisable

Range of exercise price		Number Outstanding		Weighted Average Remaining Contractual Life (in years)	Weighted Average Exercise Price		Number Exercisable		Weighted Average Exercise Price

$	0.35		1,362,000	4.64 years	$	0.35		1,362,000	$	0.35

At March 31, 2012 and December 31, 2011, the total intrinsic value of warrants outstanding and exercisable was $0 and $0, respectively.

F-59

Note 8 Commitments and Contingencies

Litigations, Claims and Assessments

On May 18, 2012, Stratex filed a complaint against Petrogulf Corporation in the U.S. District Court for the District of North Dakota alleging breach of an agreement to assign to Stratex a non-operating, working interest in certain oil wells and oil & gas leases. Stratex seeks specific performance of the disputed agreement, an award of compensatory damages to be determined at trial, but in no event less than $50 million, plus interest, costs incurred in connection with this litigation and such relief as the court may deem proper. Petrogulf Corporation seeks declaratory judgment and monetary damages related to and arising from our complaint filing.

Oil and Gas Prices

Environmental Liabilities

Note 9 Subsequent Events

The Company has evaluated for any subsequent events through June 27, 2012, which is the date these financial statements were available to be issued.

F-60

Common Stock Issuances

During the period April 1, 2012 to June 27, 2012, the company sold 10,187,857 shares of the Company’s common stock for gross proceeds of $1,513,815.

On April 19, 2012, a noteholder converted $25,000 of principal and interest of $1,165 into 104,658 shares of the company’s common stock at a conversion rate of $0.25/share.

Employment Contracts

On April 1, 2012, the Company entered into an Executive Employment Agreement with the Chief Executive Officer. The terms of the Agreement are as follows:

·	Term - 5 years,

·	Compensation - $250,000 salary per annum, bonus eligibility, (annual raises equal to 10%)

·	Option Grant - 3,000,000 options to acquire restricted stock,

·	Preferred Share Grant - 50 shares of Preferred Stock which entitle the CEO to 50 million votes on all matters submitted to a vote of the shareholders of the Company.

On April 1, 2012, the Company entered into an Executive Employment Agreement with the Chief Operating Officer. The terms of the Agreement are as follows:

·	Term - 5 years,

·	Compensation - $250,000 salary per annum, bonus eligibility, (annual raises equal to 10%)

·	Option Grant - 3,000,000 options to acquire restricted stock,

·	Preferred Share Grant - 50 shares of Preferred Stock which entitle the COO to 50 million votes on all matters submitted to a vote of the shareholders of the Company.

F-61

Stratex Oil & Gas Holdings, Inc. - FORM 8-K/A - June 5, 2013

Stratex Oil & Gas Holdings, Inc. Reports