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EXCEL - IDEA: XBRL DOCUMENT - Stratex Oil & Gas Holdings, Inc.Financial_Report.xls
EX-32.1 - CERTIFICATION - Stratex Oil & Gas Holdings, Inc.f10k2014ex32i_stratexoil.htm
EX-31.1 - CERTIFICATION - Stratex Oil & Gas Holdings, Inc.f10k2014ex31i_stratexoil.htm
EX-32.2 - CERTIFICATION - Stratex Oil & Gas Holdings, Inc.f10k2014ex32ii_stratexoil.htm
EX-23.1 - CONSENT OF PINNACLE ENERGY SERVICES, LLC - Stratex Oil & Gas Holdings, Inc.f10k2014ex23i_stratexoil.htm
EX-99.4 - PINNACLE ENERGY SERVUCES LLC ENGINEERING REPORT - Stratex Oil & Gas Holdings, Inc.f10k2014ex99iv_stratexoil.htm
EX-31.2 - CERTIFICATION - Stratex Oil & Gas Holdings, Inc.f10k2014ex31ii_stratexoil.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

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

 

For the fiscal year ended December 31, 2014

 

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

 

For the transition period from ________ to ________

 

Commission File Number 333-164856

 

STRATEX OIL & GAS HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

 

Colorado   94-3364776

(State or other jurisdiction of

incorporation or organization)

  (IRS Employer
Identification No.)

 

175 South Main Street, Suite 900

Salt Lake City, UT 84111

(Address of principal executive offices)

 

(801) 519-8500

(Registrant’s telephone number, including area code)

 

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

None

 

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

Common Stock, $0.01 par value per share

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ☐ No ☒

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes ☐ No ☒

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒ No ☐

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ☒ No ☐

 

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

 

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

 

Large Accelerated Filer ☐ Accelerated Filer ☐
Non-Accelerated Filer ☐ (Do not check if a smaller reporting company) Smaller Reporting Company ☒

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No ☒

 

The issuer had 120,737,337 shares of common stock outstanding as of March 31, 2015. The aggregate market value of the common stock held by non-affiliates was approximately $30,184,334 based upon the reported sales price of $0.25 which was the average price of the last business day of the previous second quarter on the OTCBB.

 

 

 

 
 

 

Stratex Oil & Gas Holdings, Inc.

Table of Contents

 

  Page
Contents  
FORWARD-LOOKING STATEMENTS 3
GLOSSARY OF TERMS 4
PART I 6
ITEM 1. BUSINESS 6
ITEM 1A.  RISK FACTORS 31
ITEM 1B. UNRESOLVED STAFF COMMENTS 45
ITEM 2. PROPERTIES 45
ITEM 3.  LEGAL PROCEEDINGS 45
ITEM 4. MINE SAFETY DISCLOSURES 45
PART II 46
ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 46
Market Information 46
ITEM 6.  SELECTED FINANCIAL DATA 49
ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 49
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 56
ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 56
ITEM 9A.  CONTROLS AND PROCEDURES 56
ITEM 9B.  OTHER INFORMATION 57
PART III 57
ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 57
ITEM 11.  EXECUTIVE COMPENSATION 60
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 63
ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 64
ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES 65
PART IV 67
ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 67
SIGNATURES 68

 

2
 

 

FORWARD-LOOKING STATEMENTS

 

The statements contained in this annual report on Form 10-K that are not historical facts represent management’s beliefs and assumptions based on currently available information and constitute “forward-looking statements.” These statements include, but are not limited to, any statement that may predict, forecast, indicate or imply future results, performance, achievements or events. These forward-looking statements address matters that involve risks and uncertainties. Accordingly, there are or will be important factors that could cause our actual results to differ materially from those indicated in these statements. We believe that these factors include but are not limited to the following:

 

uncertainty regarding our ability to raise the funds necessary to pay our current liabilities and carry out our business plan;
   
the continuing adequacy of our capital resources and liquidity including, but not limited to, access to borrowing capacity;
   
the availability (or lack thereof) of acquisition, disposition or combination opportunities;
   
domestic and global supply and demand for oil and natural gas;
   
sustained, increased or further declines in the prices we receive for oil and natural gas;
   
the geologic quality of our properties with regard to, among other things, the existence of hydrocarbons in economic quantities;
   
uncertainties about the estimates of our oil and natural gas reserves;
   
our ability to increase our production of oil and natural gas income through exploration and development;
   
our ability to successfully apply horizontal drilling techniques and tertiary recovery methods;
   
the number of well locations to be drilled, the cost to drill, and the time frame within which they will be drilled;
   
the effects of adverse weather on operations;
   
drilling and operating risks;
   
the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services;
   
the availability of equipment, such as drilling rigs and related equipment and tools;
   
changes in our drilling plans and related budgets;
   
uncertainties associated with our legal proceedings and their outcome;
   
the effects of government regulation, permitting, and other legal requirements;
   
uncertainties regarding economic conditions in the United States and globally;
   
difficult and adverse conditions in the domestic and global capital and credit markets; and
   
other factors discussed under “Item 1A – Risk Factors”.

 

You can often identify these and other forward-looking statements by the use of words such as “may,” “will,” “could,” “would,” “should,” “expects,” “plans,” “anticipates,” “estimates,” “intends,” “potential,” “projected,” “continue,” or the negative of such terms, or other comparable terminology. Forward-looking statements also include the assumptions underlying or relating to any of the foregoing statements.

 

These statements are based on current expectations and assumptions regarding future events and business performance and involve known and unknown risks, uncertainties and other factors that may cause industry trends or our actual results, level of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by these statements.

 

Although we believe that expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. We will assume no obligation to update any of the forward-looking statements to conform these statements to actual results or changes in our expectations, except as required by law. You should not place undue reliance on these forward-looking statements.

 

3
 

 

GLOSSARY OF TERMS

 

The following definitions shall apply to the technical terms used in this report.

 

Anticlinal structure or fold are geological formations where layers of rock have been folded into an arch shape, which can include favorable formations for oil and gas drilling, such as doubly plunging or faulted anticlines, culminations, and structural domes.

 

Bblmeans barrel or barrels.

 

BOEmeans barrels of crude oil equivalent.

 

Boepd means barrels of crude oil equivalent per day.

 

Bopdmeans barrels of crude oil per day.

 

Condensatesare hydrocarbons that exist in a gaseous state within the native reservoir environment, but condense to a liquid state due to pressure and/or temperature changes caused during the drilling, completion, or production stages of well development.

 

Development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Dry hole is an exploratory or development well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well.

 

“Farm-in” is a contractual relationship where a company acquires an interest in an operation owned by another operator.

 

Gross acres refer to the number of acres in which we own a working interest.

 

Gross well is a well in which we own a working interest.

 

MBbls means thousand barrels.

 

MCF means thousand cubic feet of gas.

 

MMBbls means million barrels.

 

MMcfmeans million cubic feet of gas.

 

Mud-log report” is a report which sets forth data regarding geological structure and hydrocarbon presence maintained at the time a well is drilled.

 

Net acres represent Stratex’s percentage ownership of gross acreage. Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).

 

Net well represents Stratex’s percentage ownership of a gross well. A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.

 

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

 

Productive well is an exploratory or a development well that is not a dry hole.

 

4
 

 

Proved developed reserves (PDPs) are proved reserves that can be expected to be recovered:

 

1.Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; or

 

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

 

Proved reserves” or “reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

 

1.Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

 

2.Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

 

3.Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

 

Proved undeveloped reserves (PUDs) are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

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

 

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

 

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

 

“Seismic imaging” is a tool that bounces sound waves off underground rock structures to reveal possible oil- and gas-bearing formations. Seismologists use ultrasensitive devices called geophones to record the sound waves' echoes within the earth. By studying the echoes, petroleum geologists seek to calculate the depth and structures of buried geologic formations. This analysis may help them identify oil- and gas-bearing reservoirs hidden beneath the earth's surface.

 

“Sidetrack” is a process using a whipstock, turbodrill, or other mud motor to drill around broken drill pipe or casing that has become lodged permanently in the hole, or is used to bypass other formation damage.

 

SWD” means saltwater disposal well.

 

5
 

 

PART I

 

ITEM 1. BUSINESS

 

Stratex Oil & Gas Holdings Inc. (“Stratex,” “we,” “us” or “our”). We are an independent oil and gas exploration and production company with projects in Texas, Montana, Colorado, Kansas, North Dakota and Utah. The focus of our business is acquiring, retrofitting and operating or selling oil and gas assets and related production.

 

Our History

 

We were originally incorporated as Poway Muffler and Brake Inc. in California on August 15, 2003 to enter the muffler and brakes business. On December 15, 2008, a merger was effected with Ross Investments Inc., a Colorado shell corporation. Ross Investments was the acquirer and the surviving corporation. Ross Investments Inc. then changed its name to Poway Brake and Muffler Inc. On May 25, 2012, we filed an Amendment to our Certificate of Incorporation by which we changed our name from Poway Muffler and Brake, Inc., a Colorado corporation, to Stratex Oil and Gas Holdings, Inc., with the Secretary of the State of Colorado.

 

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

 

On December 1, 2014, pursuant to the terms and condition of the Agreement and Plan of Merger dated May 6, 2014 by and among Stratex, Richfield Acquisition Corp. (“Merger Sub”), and Richfield Oil & Gas Company (“Richfield”), as amended by Amendment No. 1 to Agreement and Plan and Merger dated July 17, 2014 (the Agreement and Plan of Merger, as so amended, the “Merger Agreement”), Merger Sub merged with and into Richfield, with Richfield continuing as the surviving corporation and as a wholly owned subsidiary of Stratex (the “Richfield Merger”). Prior to the completion of the transaction, the Merger Agreement and related transactions were approved by Richfield’s stockholders at a special meeting held on November 24, 2014.

 

As a result of the Richfield Merger, each outstanding share of Richfield common stock was converted into the right to receive one share of our common stock. As a result of the Richfield Merger, we delivered an aggregate of 60,616,448 shares of our common stock to the Richfield stockholders. Those shares are registered under the Securities Act of 1933, as amended, on Stratex’s Registration Statement on Form S-4 (File No.333-198384) which included a Proxy Statement/Prospectus (the “Proxy Statement/Prospectus”).

 

Neither Richfield nor any of its predecessors, subsidiaries or affiliates has been affiliated with or in any way related to Richfield Oil Corporation, an oil company based in California that was merged out of existence in 1966, or its successor, Atlantic Richfield Company.

 

6
 

 

Corporate Structure

 

The following chart shows the current corporate structure of Stratex and its subsidiaries.

 

 

 

Stratex Oil & Gas Holdings, Inc., a Colorado corporation was formally known as Poway Muffler and Brake Inc. and was formed on August 15, 2003. On May 25, 2012 Stratex changed its name from Poway Muffler and Brake Inc to Stratex Oil & Gas Holdings, Inc. Richfield Oil & Gas Company, a Nevada corporation was formally known as Hewitt Petroleum, Inc and was formed on May 18, 2008. On March 4, 2011 Richfield changed its name from Hewitt Petroleum to Richfield Oil & Gas Company. Hewitt Energy, Inc. was acquired by Hewitt Petroleum, Inc. from Hewitt Energy Group, LLC effective on January 1, 2009 Hewitt Energy, Inc. is licensed and bonded in Kansas to be an Operator. Stratex Operating, Inc. was formed on December 2, 2014, and is licensed to be an Operator in Kansas, Texas and Montana. Stratex Land, Inc, a Nevada corporation was incorporated to hold the oil & gas leases of the Company. The two subsidiaries of Stratex Land, Inc. were formed to hold oil and gas leases within Utah and Kansas. On June 25, 2013 HOI Kansas Property Series, LLC, a Kansas series limited liability company, was organized to hold the oil and gas leases within the State of Kansas. On December 2, 2014 the name for HOI Kansas Property Series, LLC was changed to Stratex Kansas Property Series, LLC. On August 5, 2013 HOI Utah Property Series, LLC, a Utah series limited liability company, was organized to hold the oil and gas leases within the State of Utah. On December 9, 2014 the name for HOI Utah Property Series, LLC was changed to Stratex Utah Properties Series, LLC.

 

Our Business Strategy

 

We have the following strategic direction:

 

  We use our research technology to identify prospective properties in Kansas and Oklahoma that were initially developed between the 1920s and 1950s, but which may be subject to further development through the use of more modern production techniques. We refer to these properties as our “Mid-Continent Project,” which currently includes 2,186 gross (2,151 net) acres. We have identified significant oil and natural gas reserves from these early exploration properties, many of which were previously underdeveloped due to inefficient and antiquated exploration and production methods and low commodity prices. In most cases these wells were developed and left fallow by major oil and gas companies. Using current technology and methodologies, we have successfully developed both production and proved reserves within these fields, and we intend to continue to pursue this strategy in the future.  
     
  We have two properties on the Utah–Wyoming Overthrust. We currently own or lease 1,671 gross (1,671 net) acres on the Utah-Wyoming Overthrust, near the border between northern Utah and south-western Wyoming. We refer to these properties as our “Utah-Wyoming Overthrust Project.” We intend to conduct additional development activities with respect to our Utah-Wyoming Overthrust Project.

 

7
 

 

  We have participated in exploration for oil and natural gas reserves in the Central Utah Overthrust region, where we are participating in 27,293 gross (7,013 net) acres. In addition to that acreage, we have options on an additional 15,090 gross (13,669 net) acres.  We refer to these properties as our “Central Utah Overthrust Project.” We and our partners intend to conduct further drilling operations, acquire additional acreage and to conduct further exploration activities with respect to our Central Utah Overthrust Project.
     
 

In Texas, we have interests in certain properties located in Zavala County. Our Zavala County acreage lies near the established oil rim of the very prolific Eagle Ford Shale play (“Eagleford”), one of the most actively drilled basins in the United States. The play is also known for multiple stacked pay zones and is also highly prospective for the San Miguel, Austin Chalk and Buda Limestone formations, which all produce within the general vicinity.  We are currently participating in 19,792 gross (18,772 net) acres. Management views our Zavala County acreage as the cornerstone of its present development program. The Company currently owns interest in two wells which have been drilled, but not currently completed and one well which is currently being drilled.

     
 

In Roosevelt County Montana, we have interests in 420 gross (420 net) acres of leases with one producing well, which we operate. This well provides steady production and income for the company. In addition to this, the company has a small carried working interest in deeper formation, which may be drilled for, by other operators.

 

  The Company holds small, passive, non-operated working interests in Colorado, North Dakota, Montana and Kansas.  The Company currently owns an interest in 40 wells, 39 of which are currently producing. We hold approximately 48,720 gross (411 net) leasehold acres in Weld County Colorado, Sheridan County Montana, Billings, Williams, Divide, Mountrail, and Stark Counties, North Dakota, and Ford and Lane Counties Kansas. 
     
  We also have undrilled leases in Montana and North Dakota, consisting of 4,916 gross (4,916 net) acres.

 

Our approach to acquiring leases and developing producing properties focuses on three types of development activities:

 

  Activities involving the identification, acquisition and development of leases of property in which oil or natural gas is known to exist.
     
  Activities involving low or moderate exploration and development risk. These include leases of property where oil and natural gas has been produced in the past but there are no existing wells.
     
  Activities involving the acquisition of properties where it is reasonably believed that potential hydrocarbon values exist based on analysis involving geochemical, radiometric, gravitational and seismic data. This may include projects that have never been drilled or tested for oil and natural gas in the past.

 

We have developed a database to evaluate wells that are on record in our Kansas and Oklahoma areas of operation. The database contains extensive well records, including information on historic production, geological data, well depth, well logs and drilling records, and where available, handwritten driller notes concerning rock formation depths and other relevant information. This system has been developed internally from data obtained from appropriate state agencies and private organizations. The database enables us to identify potential bypassed hydrocarbons throughout the state of Kansas and parts of Oklahoma.

 

Through statistical modeling and data evaluation, we believe greater oil and natural gas reserves exist and can be found, measured and produced in areas where initial reserves were previously found but abandoned prior to full development. We believe that with our current technologies and systems, acquiring and developing older fields mitigates exploration risk and is a safe and predictable method of managing our business.

 

8
 

 

Properties

 

Office location

 

The Company maintains its corporate office at 175 S Main Street, Suite 900, Salt Lake City, UT 84111. Additionally, we have an office at 30 Echo Lake Road, Watertown, CT. 06795.

 

Oil & Gas Properties

 

We are an independent energy company focused on the acquisition and subsequent exploitation and development of predominantly crude oil as an Operator in Montana, Texas, Kansas and Utah as well as varied non-operated working interests in Colorado, North Dakota, Montana and Kansas. We are currently participating in 104,997 gross (35,317 net) acres of owned mineral rights and leasehold interests, and have been involved in conducting seismic surveys, and drilling projects in these states. As of March 31, 2015, we had 86 total wells, including 55 producing wells, 19 shut-in wells, nine active saltwater disposal wells and three wells that are currently in the process of drilling and completion. As set forth in our Reserves and Engineering Evaluation, dated March 24, 2015, and effective as of December 31, 2014 (the “2014 Pinnacle Reserve Report”), prepared by Pinnacle Energy Services L.L.C. (“Pinnacle”), as of December 31, 2014 we had 49 producing wells, 18 shut-in wells, nine active saltwater disposal wells and five wells that we were in the process of drilling and completing. For additional information, please see the 2014 Pinnacle Reserve Report which is filed herewith as Exhibit 99.4.

 

Since December 31, 2014 we have sold our Working Interest in one field located in Zavala Texas which contained 2,629 gross (1,315 net) leasehold acres and containing 1 producing well, and 5 shut in wells. This field was not economic due to the substantial fall in oil pricing.

 

Mid-Continent Project

 

In 2009, we began development of our Mid-Continent Project by selling working interests to third parties to provide development funding. As of March 31, 2015, we had three fields in our Mid-Continent Project, which contain 15 total wells, including six producing wells, five shut-in wells, and four saltwater disposal wells. We have three Kansas fields, which include:

 

The Perth Field, in Sumner County, which we own a 100% working interest and which contains four total wells, including two producing wells, one shut-in well, and one saltwater disposal well;

 

The South Haven Field, in Sumner County, which we own a 100% working interest and which contains four total wells, including two producing wells, one shut-in well, and one saltwater disposal well;

 

The Koelsch Field, in which we own an 85.5% working interest, with the exception of the RFO Koelsch #25-1 Well in which we own an 83.5% working interest. The Koelsch Field contains five total wells including two producing wells; two shut-in wells; and one saltwater disposal well; and
   
 The Gorham Field, in which we own a 100% working interest and which contains 21 total wells, including seven producing wells, 10 shut-in wells, and four saltwater disposal wells.
   
 The Trapp Field, in which we own a 100% working interest and which contains three total wells, including one producing well, one shut-in well, are one saltwater disposal well.

 

We have one project in Oklahoma, the Bull Field, in which the leases have currently expired that contain two wells, including one shut-in well and one saltwater disposal well. Our current total acreage position in our Mid-Continent Project is 2,186 gross (2,151 net) acres.

 

Utah-Wyoming Overthrust Project

 

We have two prospects in the Utah-Wyoming Overthrust Project, the Hogback Ridge Prospect and the Spring Valley Prospect. The Hogback Ridge Prospect, located in Rich County, Utah, incorporates 1,511 acres, in which we own a 100% working interest. The Spring Valley Prospect, located in Uinta County, Wyoming, incorporates a 160 acre parcel of land, in which we own the mineral rights and a 100% working interest. Our total acreage position in the Utah-Wyoming Overthrust Project is 1,671 gross (1,671 net) acres.

 

9
 

 

Central Utah Overthrust Project

 

We have five prospects in the Central Utah Overthrust Project, the Liberty Prospect, the HUOP Freedom Trend Prospect, the Independence Prospect, the Pine Springs Prospect, and the Edwin Prospect, which include one producing well, one shut-in well and one well in the completion stage of development.

 

The Liberty Prospect incorporates approximately 447 gross (106 net) acres, in which we own a 65.2% working interest before payout (“BPO”) and a 50.1% working interest after payout (“APO”). We have one well in the Liberty Prospect, which we refer to as the “HPI Liberty #1 Well.” We began drilling the HPI Liberty #1 Well in April 2010. On November 1, 2014 we sold most our interest in the Liberty #1 Well but retained a 7.5% carried working interest in the well and the 320 acre lease the well is located on. The Liberty #1 Well is currently in the completion stage of development.

 

The HUOP Freedom Trend Prospect is located in Sanpete County Utah. As of March 31, 2015 we hold lease on approximately 5,316 gross (4,775 net) leasehold acres. The Company also holds an option to acquire an additional 13,531 gross (12, 110 net) leasehold acres within the HUOP Freedom Trend Prospect. This option may be exercised on or before June 30, 2015. The Company owns an 89.5% working interest BPO and APO in the deep zones and we own a 44.3% working interest BPO and a 41.3% working interest APO in the first well to be drilled in the shallow zones. We own a 44.3% working interest BPO and APO in all wells to be drilled in the other shallow zones.

 

The Independence Prospect incorporates approximately 20,000 gross (600.0 net) acres, in which we own a 3.0% working interest and which contains one shut-in well we refer to as the “Moroni #1-AXZH and one well referred to as the Moroni #11M-1107 Well which is currently operated by Whiting Energy which was drilled in 2014, and is now producing.

 

The Pine Springs Prospect incorporates 400 acres, in which we own a 100% working interest BPO and APO. The Company also holds an option to acquire an additional 1,558 gross (1,558 net) leasehold acres within the Pine Springs Prospect.

 

The Edwin Prospect incorporates 1,131 acres, in which we own a 100% working interest BPO and APO.

 

Our total acreage position in the Central Utah Overthrust Project is 27,293 gross (7,013 net) acres. The Company also holds an option to acquire an additional 15,090 gross (13,669 net) leasehold acres within the Central Utah Overthrust Project.

 

Zavala County, Texas Project

 

On December 3, 2013 we entered into a Joint Development Agreement (the “JDA”) with Eagleford Energy, Inc., (“Eagleford”) and its wholly owned subsidiary, Eagleford Energy, Zavala Inc. (“Eagleford Zavala”). Subject to the satisfaction of certain terms and conditions in the JDA, Eagleford Zavala granted the Company the exclusive right to operate and develop approximately 2,629 gross (1,315 net) leasehold acres under a certain lease, located in Zavala County, Texas. The Company performed its obligation to earn an interest in the lease. In March 2015 the Company determined that the cost of the Royalties under the lease made the operation of this lease uneconomic. The Company surrendered its interest in this lease to its partners under the terms of the JDA on March 31, 2015. The parties entered into a mutual release of all obligations.

 

The Company holds an interest in 19,792 gross (18,772 net) leasehold acres known as the Matthews Lease. The Companies interest in the lease is a 94.85% working interest. This lease currently has two wells which have been drilled, but not currently completed, and one well that is currently being drilled. The Company owns a 94.85% working interest in these two wells and a 71.25% net revenue interest. On March 13, 2015 the Company entered into a Joint Development Agreement with Itasca Energy LLC (“IE”) whereby IE will drill up to 6 wells in the Buda Limestone formation of the leasehold to earn a 77.5 % working interest in the 6 wells which are completed, the Company will retain a 21.3% working interest in each well. IE will pay all cost of development through the tanks on the six wells. If IE completes all six wells they will earn a 77.5 % working interest in 10,314 gross (7,994 net) working interest in the Matthews Lease and 50% working interest in 9,333 gross and (4,666 net) in the remaining portion of the Matthews Lease. The first well of this agreement was spudded on March 16, 2015 each of the 5 remaining wells must be spudded within 120 days of the prior well reaching total depth. If the wells are not spudded with the required time period then IE will earn its interest in the actual wells drilled only and will not earn an interest in the total lease.

 

Our total acreage position in the Zavala County Texas Project is 19,792 gross (18,772 net) acres.

 

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Tininenko Project, Roosevelt, Co. Montana

 

Stratex owns a 100% Working interest in approximately 420 gross and 420 net mineral acres, with one producing well, in Roosevelt County, Montana with one operating well. The Operating well (Tininenko 4-19) is producing. Stratex holds a 100% working interest in this well.

 

In addition to this, the company has a small carried working interest in deeper formation, which may be drilled for, by other operators.

 

Non-Operated Working Interest

 

The Company presently owns small, non -operated working interests in the following fields as of March 31, 2015:

 

Kansas Wells – 2,080 gross and 88 net mineral acres located in Acres located in Lane County, Kansas with 8 producing wells. The lease currently has 4 producing wells with an average royalty interest of 1.20%, one producing well with a 5.0% working interest, and 3 producing wells with an average working interest of 8.048%. There is also additional spacing for 18 wells.

 

Gunsmoke Field, in which we own a 75.0% working interest until payout and a 50.0% working interest after payout. This field contains one producing well, and approximately 160.0 gross (80.0 net) acres of leasehold.

 

Olson Well – 640 gross and 2 net mineral acres in Divide County, North Dakota. We have acquired small leasehold in Divide County, North Dakota. The lease currently has 1 well with a working interest of 0.3125%.

 

Fortuna Wells – Approximately 8,902 gross and 145 net mineral acres in Billings, Stark, and Williams Counties, North Dakota, , and Sheridan County Montana, with 7 operating wells. Stratex holds an average of 1.622797 % working interest in these wells.

 

Double LL Wells – Approximately 20,480 gross and 53 net mineral acres in Billings and Stark County, North Dakota, with 15 producing wells, and one well in the completion stage of development. Stratex holds an average of 0.259433% working interest in these wells.

 

Wattenberg Lease – Approximately 16,458 gross and 67 net mineral with 7 wells that are currently producing in Weld County Colorado. Stratex holds an average of 0.405563% working interest in these wells.

 

The following represent our mineral lease holdings as of March 31, 2015. These leases contain no wells.

 

3,853 gross and 3,853 net mineral acres in Golden Valley County, North Dakota. We have leaseholds totaling 3,853 gross acres in Golden Valley County, 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 Formation.

 

786 gross and 786 net mineral acres located in Sheridan County, Montana.

 

121 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.

 

120 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.

 

32 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.

 

4 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.

 

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General Development of the Business

 

During the last three fiscal years, Stratex has raised capital through private placements of equity and debt financings. During the periods ended December 31, 2014, 2013, and 2012, Stratex raised $0, $35,000 and $1,512,735 in cash from the private placement of common stock and $18,402,210, $1,630,000 and $335,000 in cash from debt financings, respectively. On December 1, 2014 Stratex acquired Richfield Oil and Gas through the Richfield Merger in which Stratex assumed $4,114,183 in debt and issued 60,616,448 common shares valued at $8,183,220.

 

We have nine full-time employees and one consultant providing us services, and we expect that the number of our employees in 2015 will remain the same. Our technical staff focuses on the development and exploration of oil drilling projects, and evaluating the probability of encountering economically recoverable hydrocarbons.

 

We employ integrated analysis including geology, geophysics and reservoir engineering to determine the viability of a drilling prospect. We prefer to drill in areas where there are multiple zones potentially containing hydrocarbons rather than a single target, which we refer to as “stacked pay.” Although we cannot be certain whether any of the zones contain hydrocarbons, the stacked pay approach reduces the risk of a dry hole. Additionally, we look for properties with access to existing infrastructure to transport and process the products produced. Once we have conducted a full review of these factors and confirmed the viability of a prospect, we proceed with acquiring rights to the lands and resources. These lands may be acquired through direct acquisition of existing oil and natural gas production, leasehold acquisitions or farm-ins.

 

Projects

 

Our development plans may be delayed and are dependent on certain conditions, including the receipt of necessary permits, the ability to obtain adequate financing and weather conditions. Uncertainties associated with these factors could result in unexpected delays. In addition, the feasibility of a number of the projects described below is still subject to further geological testing and/or drilling to determine whether commercial quantities of hydrocarbons are present.

 

In addition to the projects currently under development, we intend to initiate the development of additional projects from time to time. However, the number of development activities we initiate each year will depend on a number of factors, including the availability of adequate financing, the availability of mineral leases, the demand for oil and natural gas, the number of properties we have under development, and our available resources to devote to our project development efforts.

 

The current status of each of our projects is described below:

 

Mid-Continent Project

 

Our Mid-Continent Project includes five fields in Kansas, which are described below:

 

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Perth Field

 

The Perth Field is located in Sumner County, Kansas. The Perth Field was discovered in 1945 and has produced a total of 1.84 million barrels of oil from the Wilcox Formation based on information maintained by the Kansas Corporation Commission. The field was mostly abandoned in the 1980s. Our research indicates that this field has high water content that is compatible with our production methodology and has the potential of producing a significant amount of additional oil. There are also other zones in this field, which have not been fully tested, that we believe could contain additional reserves. These zones include Lansing/Kansas City, Mississippi, and Arbuckle.

 

We have drilled and completed three production wells in the Wilcox Formation and equipped them with submersible pumps. We own a 100% working interest in the Perth Field, which incorporates 320 acres. As of March 31, 2015, the Perth Field contained two producing wells, one saltwater disposal well and one well that is shut in. Our development plan contained in the 2014 Pinnacle Reserve Report includes drilling three new wells, one recompletion, and one reentry, all for production from the Wilcox. We also anticipate the need for drilling one new saltwater disposal wells in the future.

 

South Haven Field

 

The South Haven Field is located in Sumner County, Kansas. The South Haven Field was discovered in 1954 and produced over 600,000 barrels of oil through 1977, when the field was abandoned, according to data maintained by the Kansas Corporation Commission. All of the oil production came from the Wilcox Formation. Our research indicates that this field has strong water drive compatible with our production methodology. We believe that the South Haven Field has the capability of producing substantially more oil than has been produced in the past. There have been excellent shows of oil and natural gas in both the Wilcox and the Mississippi Chat present during our testing of the field. However we have not completed any wells in the Layton, Cleveland, or Mississippi Chat Formations. We own a 100% working interest in the South Haven Field, which incorporates 247 acres.

 

We have drilled and completed two new wells, the RFO Helsel #3-1 and the Yearout #2-1, in the South Haven Field. The Helsel #3-1 well was put into production in September 2013; currently this well is producing. The Yearout #2-1 was drilled during 2014 and is also producing. We have recompleted the existing well, the Rusk #2, in the Wilcox Formation and it is in production. We have also washed down a previously plugged well for conversion to a saltwater disposal well and the well is now active. As of March 31, 2015, the South Haven Field contained two producing wells, one saltwater disposal well and one shut in well. Our development plan calls for drilling two new wells, and recompleting on well, for production from the Wilcox Formation, one horizontal well for production from the Mississippian Limestone and one new salt water disposable well.

 

Koelsch Field

 

The Koelsch Field, which includes the Prescott Lease, is located in Stafford County, Kansas, consists of 240 acres, in which we own an 85.50% working interest, with the exception of the RFO Koelsch #25-1 Well in which we own an 83.50% working interest. This field was discovered in 1952 and has produced over 500,000 barrels of oil with some reported natural gas production, according to data maintained by the Kansas Corporation Commission. The Arbuckle reservoir in this field has been largely abandoned since 1957. We believe that the Koelsch Field has the capability of producing substantially more oil than has been produced in the past. In January 2012, we drilled the RFO Koelsch #25-1 Well which went into production in April 2012. In March 2012, we drilled the RFO Prescott #25-6, which we put into production, but is currently shut-in. In 3Q 2014, we performed a polymer treatment on the Prescott #2 Well which increased the production and lowered the costs of operation. As of March 31, 2015, the Koelsch Field contained two producing wells, two shut-in wells and one active saltwater disposal well. Our plans relating to the Koelsch Field include: i) drilling three new wells for production from the Arbuckle Formation; ii) drilling one new horizontal well for production from the Mississippian Limestone; iii) reconfiguring two existing shut-in wells for production; iv) drilling an additional saltwater disposal well; and v) performing a polymer gel water shut off treatment on one of the existing producing wells.

 

Additionally, we have reviewed mud-log reports that indicate the presence of at least 22 shallow natural gas zones in the Koelsch Field, which exhibit low British Thermal Unit (“BTU”) content gas. The low BTU gas content of these wells is due in large part to significant Helium deposits together with Nitrogen. Helium by itself is a valuable gas and if we desire to produce gas, the wells will require the installation of portable separation plants to extract Helium and waste Nitrogen from the natural gas. This process is expected to increase the BTU content of the natural gas and create additional value from the sale of Helium.

 

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Gorham Field

 

During 2014 we owned and operated a portion of the Gorham Field is located in Russell County, Kansas. Stratex’ Gorham Field leaseholds contained a total of 1,219 acres. The field was discovered in 1926 and has produced approximately 98,000,000 barrels of oil for former producers, 67% of which has come from the Upper Arbuckle and Reagan Reservoirs, and 25% of which has come from the Lansing/Kansas City formation, according to data maintained by the Kansas Corporation Commission as of December 31, 2014, the Gorham Field contained seven producing wells, 10 shut-in wells, and four active saltwater disposal wells. Our development plan included reworking nine shut-in wells and drilling 25 new wells for production from the Arbuckle Formation and Gorham Sand and five additional salt water disposal wells.

 

Trapp Field

 

During 2014 we owned a portion of the Trapp Field, located in Russell County Kansas. The Trapp Field is the largest producing oil field in Kansas and has produced approximately 310,000,000 barrels of oil with very little reported natural gas production for previous producers, according to data maintained by the Kansas Corporation Commission. The Hoffman lease is located in a portion of the Trapp Field. As of December 31, 2014 we owned a 100% working interest in the Hoffman lease. This field consisted of 160 acres with respect to which we lease 100% of the mineral rights. As of December 31, 2014, the Trapp Field contained three wells, including one producing well, one shut-in well, and one saltwater disposal well. Our development plan included reworking the shut-in well, drilling four new wells for production from the Arbuckle Formation and drilling one new saltwater disposal well.

 

Utah-Wyoming Overthrust Project

 

Our Utah-Wyoming Overthrust Project includes one prospect in Wyoming and one prospect in Utah, which are described below:

 

Hogback Ridge Prospect

 

The Hogback Ridge Prospect is located in Rich County, Utah, along the Utah-Wyoming Overthrust and consists of 1,511 acres of mineral leases, with 10-year terms, in which we own a 100% working interest. Our geological research shows that our acreage covers two separate structural highs in the Jurassic Nugget Sandstone, located along a back thrust on the hanging wall of the Crawford Thrust Plate. There are other potentially productive formations that have had favorable test results throughout the area.

 

A portion of our acreage is within 3 miles of a nearby field, where American Quasar drilled the Hogback Ridge #20-1 that produced natural gas from the Dinwoody Formation, at a depth of 9,400 feet. According to the public records of the Utah Division of Oil, Gas and Mining (“UDOGM”), this well had an initial production rate of 22.4 MMcf of natural gas per day, and produced a cumulative of 5,500 MMcf of natural gas, from 1977 to 1981, before being plugged. This well also had excellent drill stem tests results in several other formations, such as the Twin Creek Limestone at 1,041 feet with a test of 15 MMcf of natural gas per day, the Phosphoria Formation at 10,020 feet with a test of 9.9 MMcf of natural gas per day, and the Weber Sandstone at 10,522 feet with a test of 10.5 MMcf of natural gas per day. A 10 inch Questar gas pipeline crosses our acreage, and connects to a nearby 22 inch Western Gas pipeline, which could be used to sell gas produced by future wells.

 

We believe that this prospect warrants further geological research in order to determine where new acreage should be acquired, and where any new wells should be drilled. Plans to drill in the Hogback Ridge Prospect have not yet been determined and no reserves have been assigned to the Hogback Ridge Prospect in the 2014 Pinnacle Reserve Report.

 

Spring Valley Prospect

 

The Spring Valley Prospect lies between the Anschutz Ranch and Pinedale Fields in Uinta County, Wyoming, along the Utah-Wyoming Overthrust. We currently own 100% of the mineral rights in a 160 acre parcel of land, containing an active oil seep. Geological research into the Spring Valley Prospect is ongoing and reviewed on an annual basis. Plans to drill in the Spring Valley Prospect have not yet been determined as we are awaiting the results of additional geological research and no reserves have been assigned to the Spring Valley Prospect in the 2014 Pinnacle Reserve Report.

 

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Central Utah Overthrust Project

 

Our Central Utah Overthrust Project includes five prospects in Utah, which are described below:

 

HUOP Freedom Trend Prospect

 

The HUOP Freedom Trend Prospect is currently owned by Hewitt Utah Overthrust Partners (“HUOP”). Ownership in the HUOP Freedom Trend Prospect has been split stratigraphically into two groups, deep rights and shallow rights. The working interest owners of the HUOP Freedom Trend Prospect have defined deep rights as all stratigraphic intervals located below the top of the Jurassic Twin Creek Formation, including the Jurassic Twin Creek Formation, and have defined shallow rights as all stratigraphic intervals located above, but not including, the Jurassic Twin Creek Formation. With respect to the HUOP Freedom Trend Prospect, we currently own an 89.50% working interest BPO and APO in the deep zones, and a 44.25% working interest BPO and APO in the shallow zones for each well, with the exception of the first well we complete in the shallow zones, in which we will own a 44.25% working interest BPO and a 41.25% working interest APO in the shallow zones.

 

The HUOP Freedom Trend Prospect consists of 5,315 gross (4,775 net) acres along the Central Utah Overthrust in Sanpete County, Utah, with respect to which we lease 100% of the mineral rights. The Company has an option to acquire an additional 13,531gross (12,110 net) acres within the HUOP Freedom Trend Prospect. This Option is exercisable on or before June 30, 2015. The HUOP Freedom Trend Prospect has attractive oil and natural gas potential relating to multiple large subsurface anticlinal structures near Fountain Green, Utah indicated by surface geology, gravity data, geochemical evidence and seismic surveys. We believe this data suggests structural closure over several square miles with a high possibility of the presence of oil and natural gas under the acres leased by HUOP. This evidence is bolstered by discoveries southwest of Fountain Green, Utah and traces of oil in wells surrounding the prospect. The main productive zones of the HUOP Freedom Trend Prospect are the Twin Creek and Navajo zones which are each repeated as three separate structures throughout the prospect, at approximate depths of 6,000, 9,000, and 12,000 feet, in separate locations on acres leased and optioned by us. A deeper Mississippian target exists at approximately 14,000 to 16,000’, which has never been drilled for in the Central Utah Overthrust.

 

There are also shallow targets within the anticlinal fold on the eastern edge of HUOP Freedom Trend Prospect’s leases at depths of 4,000 to 10,000 feet range. We believe the Entrada Sandstone and the Cretaceous zones of the Emery, Ferron, and Dakota formations could hold reserves. We have identified several drilling locations where these zones could be tested simultaneously by drilling one well. These zones are accessible through conventional drilling techniques.

 

There are no wells currently on the HUOP Freedom Trend Prospect. We plan to drill wells so that three overlapping Navajo layers in three different structures can be tested in one well, all within prospect boundaries. Our long-term development plans for the HUOP Freedom Trend Prospect include drilling on 80-acre spacing in multiple reservoirs. Immediate plans to drill in the HUOP Freedom Trend Prospect have not yet been determined and no reserves have been assigned to the HUOP Freedom Trend Prospect in the 2014 Pinnacle Reserve Report.

 

Liberty Prospect

 

The Liberty Prospect is owned by multiple parties. The Liberty Prospect incorporates 447 gross (115 net) mineral acres in which we lease, or own, 100% of the mineral rights. The Liberty Prospect is on the Paxton Thrust in the northernmost part of the Central Utah Overthrust in Juab County, Utah. One well has been drilled within the Liberty Prospect. We own a 7.5% carried working interest in the HPI Liberty #1 Well and the surrounding 320 acre lease in which the HPI Liberty #1 Well is located.

 

We drilled the HPI Liberty #1 Well in 2010, and as a result, we have discovered about 1,200 feet of hydrocarbon charged zone in the Twin Creek Limestone and the Navajo Sandstone, including oil, natural gas and condensates. These formations are naturally fractured, resulting in excellent permeability and enhanced secondary porosity. Petrographic analysis confirms the presence of natural gas and oil throughout the hydrocarbon charged zone, as well as 15% to 20% primary porosity in the Navajo Sandstone. The oil is similar to that of the Covenant Field and has been classified as coming from a Mississippian-aged source rock.

 

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While the HPI Liberty #1 Well was spudded in April 2010, it remains in the completion stage of development. The initial drilling of the well resulted in formation damage. We have made attempts at remediating this damage, but these attempts have thus far been unsuccessful. On November 2014 we sold our interest in the Liberty #1 Well to partners who have participated in the well in the past, retaining a 7.5% carried working interest in the well for future completion attempts.

 

The current Operator plans to drill another sidetrack in 2015, to attempt to bypass and prevent formation damage. Stratex will be carried in this work. No reserves have been assigned to the Liberty Prospect in the 2014 Pinnacle Reserve Report.

 

Independence Prospect

 

The Independence Prospect lies directly east of the Gunnison Thrust of the Central Utah Overthrust belt, in Sanpete County, Utah. As of March 31, 2015, we owned a 3.00% working interest in approximately 20,000 gross (600.0 net) acres in the Independence Prospect, which includes the Moroni #1-AXZH Well and the Moroni #11M-1107 Well. This play targets the Tununk (Mancos) Shale, in a basin centered, highly organic, liquids rich shale play. Other potential pay zones include the Emery, Ferron, and Dakota Formations.

 

In 1976, Hanson Oil Co., Inc. and True Oil, LLC drilled the Moroni #1-AXZH Well to a total depth of 21,260 feet looking for a Mississippian zone. During the drilling process, mud circulation was lost in the Tununk Shale at 11,551 feet. In 1998, Cimarron Energy, Inc. drilled five horizontal sidetracks in the Tununk Shale in the Moroni #1-AXZH Well. On Cimarron’s final failed attempt, its drill pipe became stuck. Limited perforations through the drill pipe in the Tununk Shale have tested with rates equivalent to 720 Bopd, but such rates were only sustained for one to two hours at a time. Severe mechanical constrictions and formation damage have combined to make it uneconomical in its current mechanical configuration and have led to the well being shut-in.

 

On August 28, 2014 Whiting Oil & Gas Corp. began the drilling of the Moroni #11M-1107 well in Sanpete County Utah. We own a 3% working interest in the Moroni #11M-1107 well. As of March 31, 2015 the well has been drilled and fractured treated. First production began on February 19, 2015, but the well did not go into full production until March 17, 2015. While the well is now in production, a majority of the frac load still needs to be recovered, before full production rates can be realized. We plan to participate in the development of the Independence Prospect by funding our 3% working interest requirement on any further wells to be drilled within the 20,000 acre lease position. No reserves have been assigned to the Independence Prospect in the 2014 Pinnacle Reserve Report.

 

Pine Springs Prospect

 

The Pine Springs Prospect lies directly east of the Gunnison Thrust of the Central Utah Overthrust belt, in Sanpete County, Utah. As of March 31, 2015, we owned a 100.00% working interest in approximately 400 acres in the Pine Springs Prospect. The Company has an option to acquire an additional 1,558 gross (1,558 net) acres within the Prospect. This Option is exercisable on or before June 30, 2015. This acreage is in an up-dip location to a well drilled by Phillips Petroleum in 1971. The Phillips well had gas shows in the same Cretaceous formations contained in the Independence Prospect. Plans to drill in the Pine Springs Prospect have not yet been determined and no reserves have been assigned to the Pine Springs Prospect in the 2014 Pinnacle Reserve Report.

 

Edwin Prospect

 

The Edwin Prospect lies directly east of the Gunnison Thrust of the Central Utah Overthrust belt, in Sanpete County, Utah. As of March 31, 2015, we owned a 100.00% working interest in approximately 1,131 acres in the Edwin Prospect. This acreage is located on a seismically defined structural high, which contains the same Cretaceous formations as the Independence Prospect. This play targets the Tununk (Mancos) Shale, which is a highly organic, liquids rich shale play. Plans to drill in the Edwin Prospect have not yet been determined and no reserves have been assigned to the Edwin Prospect in the 2014 Pinnacle Reserve Report.

 

Zavala County, Texas Project

 

The Zavala County, Texas Project is located on the edge of the Eagle Ford Shale play in northern Zavala County, Texas. There are several other formations that are prospective within Stratex acreage such as the San Miguel Formation, the Austin Chalk, and the Buda Limestone.

 

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On December 3, 2013 we entered into a Joint Development Agreement (the “JDA”) with Eagleford Energy, Inc., (“Eagleford”) and its wholly owned subsidiary, Eagleford Energy Zavala, Inc. (“Eagleford Zavala”). Subject to the satisfaction of certain terms and conditions in the JDA, Eagleford Zavala granted the Company the exclusive right to operate and develop approximately 2,629 gross (1,315 net) leasehold acres under a certain lease, located in Zavala County, Texas. The Company performed its obligation to earn an interest in the lease. In March 2015 the Company determined that the cost of the Royalties under the lease made the operation of this lease uneconomic. The Company surrendered its interest in this lease to its partners under the terms of the JDA. On March 31, 2015, the parties entered into a mutual release of all obligations.

 

The Company holds an interest in 19,792 gross (18,772 net) leasehold acres known as the Matthews Lease. The Companies interest in the lease is a 94.85% working interest. This lease currently has two wells which have been drilled, but not currently completed, and one well that is currently being drilled. The Company owns a 94.85% working interest in these two wells and a 71.25% net revenue interest. On March 13, 2015 the Company entered into a Joint Development Agreement with Itasca Energy LLC (“IE”) whereby IE will drill 6 wells in the Buda Limestone formation of the leasehold to earn a 77.5 % working interest in those 6 wells which are completed, the Company will retain a 21.3% working interest in each well. IE will pay all cost of development through the tanks on the six wells. If IE completes all six wells they will earn a 77.5 % working interest in 10,314 gross (7,994 net) working interest in the Matthews Lease and 50% working interest in 9,333 gross and (4,666 net) in the remaining portion of the Matthews Lease. The first well of this agreement was spudded on March 16, 2015 each of the 5 remaining wells must be spudded within 120 days of the prior well reaching total depth. If the wells are not spudded with the required time period then IE will earn its interest in the actual wells drilled only and will not earn an interest in the total lease.

 

Tininenko Project, Roosevelt, Co. Montana

 

Stratex owns a 100% Working interest in approximately 420 gross and 420 net mineral acres, in the Red Bank Field, with one producing well, in Roosevelt County, Montana. The Operating well (Tininenko 4-19) is producing from the Ratcliffe Formation. Stratex holds a 100% working interest in this well.

 

In addition to this, the company has a small carried working interest in deeper formation, which may be drilled for, by other operators.

 

Small Non-Operated Properties

 

Lane County Kansas

 

Stratex owns approximately 2,080 gross and 88 net mineral acres located in Lane County, Kansas with 8 producing wells. The lease currently has 4 producing wells with an average royalty interest of 1.20%, one producing well with a 5.0% working interest, and 3 producing wells with an average working interest of 8.048%. There is also additional spacing for 18 wells.

 

Gunsmoke Project – Ford County, Kansas

 

On September 8, 2014, Stratex entered into a Joint Development Agreement (“JDA”) with Eagle Oil & Gas Co. (“Eagle”) and Eagle Dodge City Partners, LP (“EDC”), initially covering the development of approximately 35,000 acres in Ford County, Kansas. Pursuant to the JDA, Eagle, as operator, has initially drilled four (4) Obligation Wells. Three of the wells were plugged and abandoned. The fourth well is currently producing. Stratex currently has a fifty percent (50%) working interest in the O’Slash Cattle #11-1 Well. The JDA has also established an area of mutual interest (“AMI”) in Ford County, Kansas, pursuant to which Stratex and Eagle have each agreed to permit each other to acquire fifty percent (50%) of any undivided working interest in New Prospect Leases located within the AMI acquired obtained by either of us during the three (3) year term of the AMI.

 

Stratex’s current ownership in the Gunsmoke Project incorporates 160 gross (80 net) acres. As of March 31, 2015, the Gunsmoke Project contained one producing well, no saltwater disposal well and no wells that are shut in.

 

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Wattenberg Field, Weld Co. Colorado

 

Stratex owns approximately 16,458 gross and 67 net mineral acres with 7 wells that are currently producing in Weld County Colorado. Stratex holds an average of .405563% working interest in these wells. These wells are producing from the Niobrara Shale.

 

Williston Basin, North Dakota and Montana

 

Stratex owns small, non-operated Working Interests in a total of 23 producing wells, and one shut in well, in the Williston basin. The total acreage that Stratex owns in conjunction with these wells is approximately 34,938 gross (5,117 net) acres.

 

Olson Well – 640 gross and 2 net mineral acres in Divide County, North Dakota. We have acquired small leasehold in Divide County, North Dakota. The lease currently has 1 well with a working interest of 0.3125%.

 

Fortuna Wells – Approximately 8,902 gross and 145 net mineral acres in Billings, Stark, and Williams Counties, North Dakota, , and Sheridan County Montana, with 7 operating wells. Stratex holds an average of 1.622797 % working interest in these wells.

 

Double LL Wells – Approximately 20,480 gross and 53 net mineral acres in Billings and Stark County, North Dakota, with 15 producing wells, and one well in the completion stage of development. Stratex holds an average of .259433% working interest in these wells.

 

The following represent our mineral lease holdings in the Williston Basin, as of March 31, 2015. There are no wells associated with this acreage.

 

3,853 gross and 3,853 net mineral acres in Golden Valley County, North Dakota. We have leaseholds totaling 3,853 gross acres in Golden Valley County, North Dakota which were acquired under a long-term lease option. The conventional oil play consists of two objective formations; 1) Bakken – An organic rich shale with interbedded sandstone that has produced over 80M barrels of oil and is present over our acreage, 2) Three Forks/Sanish Formation.

 

786 gross and 786 net mineral acres located in Sheridan County, Montana.

 

121 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.

 

120 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.

 

32 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.

 

4 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.

 

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Trends and Cycles

 

Over the past several years, the prices for oil and natural gas have been volatile. We expect this volatility to continue. Prolonged increases or decreases in the price of oil and natural gas could have a significant impact on our results of operations and our ability to execute our business plan. There is a strong relationship between energy commodity prices and access to both equipment and personnel. High commodity prices also affect the cost structure of services which may impact our ability to accomplish drilling, completion and equipping goals in a timely fashion. Low commodity prices affect the cash flow of the Company which in turn may affect the timing of new drilling or completion projects. In addition, weather patterns are unpredictable and can cause delays in implementing and completing projects.

 

The oil and gas business is cyclical by nature, due to the volatility of oil and natural gas commodity pricing as described above. Additionally, seasonal interruptions in drilling and construction operations can occur but are expected and accounted for in the budgeting and forecasting process.

 

Competitive Conditions

 

We actively compete for reserve acquisitions, exploration leases, licenses and concessions and skilled industry personnel with a substantial number of competitors in the oil and gas industry, many of whom have significantly greater financial resources than we do. Competitors include major integrated oil and gas companies, numerous other independent oil and gas companies and individual producers and operators.

 

The oil industry is highly competitive. Our competitors for the acquisition, exploration, production and development of oil and natural gas properties, and for capital to finance such activities, include companies that have greater financial and personnel resources than we do.

 

Certain of our customers and potential customers are also exploring for oil and natural gas, and the results of such exploration efforts could affect our ability to sell or supply oil to these customers in the future. Our ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be dependent upon developing and maintaining close working relationships with our future industry partners and joint operators, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. Hiring and retaining technical and administrative personnel continues to be a competitive process. We believe our distinct competitive advantage is through our unique projects, our use of innovative scientific and engineering methods, and our integrated approach to generating and implementing drilling projects.

 

Summary of Oil and Gas Reserves

 

The following table summarizes our estimated quantities of proved and probable reserves as of December 31, 2014. See “Preparation of Reserves Estimates" on page 21 of this annual report on Form 10-K and the 2014 Pinnacle Reserve Report attached hereto as Exhibit 99.7 attached hereto for additional information regarding our estimated proved reserves.

 

   Reserve Estimates as of December 31, 2014 
Reserve Category  Oil (gross)   Oil (net)   Natural Gas (gross)   Natural Gas (net) 
   MBbls   MBbls   MMcf   MMcf 
PROVED                
Developed   5,058.4    709.0    9,196.2    272.5 
Undeveloped   1,848.1    1,477.3    873.1    698.1 
TOTAL PROVED   6,906.5    2,186.4    10,069.2    970.6 
                     
PROBABLE                    
Developed   1,457.3    1,157.8    659.6    527.1 
Undeveloped   2,336.6    1,870.5    1,133.3    907.2 
TOTAL PROBABLE   3,793.9    3,028.3    1,792.8    1,434.3 

 

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During 2014, two factors impacted our total Net Proved Undeveloped Reserves:

 

We converted all of our Net Proved Undeveloped Reserves from our 2013 LaRoche Engineering report, into Net Proved Developed Reserves.

 

We acquired a significant amount of Net Proved Undeveloped Reserves with the Richfield Merger.

 

Estimated Future Income

 

The future net revenue set forth in our 2014 Pinnacle Reserve Report includes deductions for state production (severance) taxes. Future net income is calculated by deducting these taxes, future capital costs, and operating expenses, but before consideration of any state and/or federal income taxes. The future net income has not been adjusted for any outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. The future net income has been discounted at various annual rates, including the standard 10%, to determine its “present worth.” The present worth is shown to indicate the effect of time on the value of money.

 

   Discounted Present Values (in thousands) 
Category  0%   10% 
   2013   2014   2013   2014 
Proved                
Proved Developed  $977   $28,244   $760   $13,448 
Proved Undeveloped  $76   $50,485   $30   $17,990 
Total Proved  $1,053   $78,729   $791   $31,438 
                     
Probable                    
Probable Developed   -   $65,834    -   $32,205 
Probable Undeveloped   -   $105,523    -   $43,707 
Total Probable   -   $171,357    -   $75,912 

 

The reserve values in the table above are based upon the information found in the 2014 Pinnacle Reserve Report, and the 2013 La Roche Reserve Report attached as Exhibit 99.3 to Stratex’s 2013 Form 10K, filed March 31, 2014. The values as of December 31, 2014 are based on SEC pricing guidelines, adjusted to reflect estimated differentials in our fields, and use fixed oil prices. The oil price used, before the differentials, was $91.48, and the gas price used, before differentials, was $4.35. The values as of December 31, 2013 are based on SEC pricing guidelines, adjusted to reflect estimated differentials in our fields, and use fixed oil prices. The oil price used, before the differentials, was $96.94, and the gas price used, before differentials, was $3.67.

 

Economic Assumptions

 

Pricing

 

In accordance with applicable requirements under SEC rules, estimates of our net proved reserves and future net revenues were determined according to the SEC pricing guidelines adjusted for an effective date of January 1, 2014. The regulations state that the prices for each product are to be calculated by using the unweighted arithmetic average of the first-day-of-the-month price for each month of the 12-month reporting period.

 

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The price of natural gas is based on the NYMEX Henry Hub postings and the price of oil is based on NYMEX Cushing postings. For January 1, 2014 through December 31, 2014, the unweighted arithmetic average of the first-day-of-the-month price was $4.35/MCF for natural gas and $91.48/Bbl for oil. Product prices for each well were adjusted from SEC prices to reflect estimated differentials, BTU content, field losses and usage, or gathering and processing costs.

 

Product Price with differentials, by Property

 

Oil Prices Per bbl 
SEC - Nymex   Gorham, Trapp, and Koelsch Fields, KS   Perth, South Haven, and Gunsmoke, KS   Lane Co. KS (avg.)   Williston Basin (avg.)   Tininenko   Wattenberg 
$91.48   $81.32   $87.82   $84.62   $80.56   $77.99   $81.32 

 

Natural Gas Prices per MCF 
SEC - Nymex   Gorham, Trapp, and Koelsch Fields, KS   Perth, South Haven, and Gunsmoke, KS   Lane Co. KS (avg.)   Williston Basin (avg.)   Tininenko   Wattenberg 
$4.35   $3.26   $3.26   $4.35   $6.07   $4.35   $4.35 

 

Expenses and Production Taxes

 

Well operating expenses reflect our historical cost levels applied to expected future operations. Expenses were held constant going forward. For non-producing (including behind pipe) and undeveloped locations, capital and operating expenses were based on analogy wells and provided by us, and are reasonable based on producing areas, depths, formations, and projected activity.

 

If a property is calculated to be uneconomic based on rate, expenses, and pricing, then the rate, reserves, and expenses will show zero in the reserves and economic results. However, the operator of many of these wells may continue to produce oil or gas and we will realize income and expenses from the properties not captured in this evaluation.

 

Abandonment costs were assumed to be offset by future salvageable equipment values for our properties in Kansa, which is a reasonable and common assumption for the activities projected and producing wells in the mid-continent region.

 

Severance and ad valorem taxes were applied to all wells in the economic evaluation. Severance (production) tax rates were based on applicable current state published rates for oil and natural gas. Ad valorem taxes on reserves and equipment vary by county within the states.

 

Preparation of Reserves Estimates

 

The 2014 Pinnacle Reserve Report relates to our oil and gas properties as of December 31, 2014. The 2014 Pinnacle Reserve Report was prepared by Pinnacle based on geological and production data, and other information provided by us. We accumulated historical production data for our wells, calculated historical lease operating expenses, obtained current lease ownership information, obtained authorizations for expenditures (“AFEs”) from our operations department and obtained geological and geophysical information from the geological department.

 

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We do not produce internal engineering reports, but instead provide all necessary information to our third-party engineer in connection with the preparation of our reserve and engineering evaluations. Our Geologist, Jeremiah J. Burton, provides all necessary empirical and interpreted data, including geological descriptions, cross sections, structure maps, isopach maps, well logs, and production histories for each well. This information is reviewed by our Geologist. Operating expenses and AFEs are prepared by our operations department, and are reviewed by our Geologist, our Field Operations Staff. All working interests and lease net revenue interests are reviewed by our General Counsel. Upon completion of the foregoing procedures, we provided the applicable information to Pinnacle for use in preparing the 2014 Pinnacle Reserve Report.

 

The geological and production data prepared by our Geologist and operations department was provided to Pinnacle for use in generating the 2014 Pinnacle Reserve Report. Pinnacle uses the data provided by us, as well as other publicly available data for our properties and surrounding properties to estimate our reserves. Our in-house internal Geologist, along with Management conducted a final review of the 2014 Pinnacle Reserve Report and the assumptions relied upon therein.

 

Pinnacle is licensed as a Registered Professional Engineering Firm in the states of Oklahoma and Texas. The managing engineer at Pinnacle primarily responsible for overseeing the preparation of estimates of our reserves is a Registered Professional Engineer in the States of Oklahoma and Texas, is a member of the Society of Petroleum Economic Evaluators, is certified by The National Council of Examiners for Engineering and Surveying, is a qualified reserves evaluator and reserves auditor under Canadian law, and holds a Bachelor of Science degree in Petroleum Engineering from the University of Tulsa. We have compensated Pinnacle for its services exclusively through payments of cash. We have not issued Pinnacle any form of our securities or granted Pinnacle an interest in any of our assets, either as compensation for services or otherwise.

 

Mr. Burton has seventeen years of experience in oil and gas exploration and production. Mr. Burton has held his position as Richfield’s, now Stratex’s Geologist for four years. Prior to joining Stratex, Mr. Burton held various positions in exploration geology, development planning, operations management, and environmental permitting with Flying J Oil and Gas Inc., The Shipley Group, LLC. and Richfield. Mr. Burton received a Bachelor of Science degree in Geology from Utah State University in 1998. He has been a member of the American Association of Petroleum Geologists and the Utah Geological Association, and the Kansas Geological Society for over Seventeen years.

 

Evaluation of Reserves

 

The reserves and values included in the 2014 Pinnacle Reserve Report are estimates only and should not be construed as being exact quantities. The reserve estimates were performed using accepted engineering practices and were primarily based on historical rate decline analysis for existing producers. As additional pressure and production performance data becomes available, reserve estimates may increase or decrease in the future. The revenue from such reserves and the actual costs related thereto may be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the prices actually received for the reserves included in the report and the costs incurred in recovering such reserves may vary from the price and cost assumptions referenced. Therefore, in all cases, estimates of reserves may increase or decrease as a result of future operations.

 

Remaining recoverable reserves are those quantities of petroleum that are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty depending primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty is conveyed by classifying reserves as proved reserves (as defined above) or unproved.

 

The estimated reserves and revenues shown in the 2014 Pinnacle Reserve Report were determined by SEC standards for proved and probable reserve categories. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing for the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable period.

 

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Proved developed reserves (“PDPs”) are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional crude oil and natural gas 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 are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

 

Proved developed non-producing (“PNP”) reserves include reserves from zones that have been penetrated by drilling but have not produced sufficient quantities to allow material balance or decline curve analysis with a high degree of confidence. This category includes proved developed behind-pipe (“PNPBP”) zones and tested wells awaiting production equipment (PNP).

 

Proved undeveloped reserves (“PUDs”) are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

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

 

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

 

Drilling and Other Exploratory and Development Activities

 

During the year ended December 31, 2012, we did not drill any dry exploratory or dry development wells or any productive exploratory or productive development wells.

 

During the year ended December 31, 2013, we drilled one gross (1.00 net) dry exploratory well. We drilled three gross (3.00 net) productive exploratory wells. We drilled 26 gross (2.54 net) productive development wells, on a non-operated basis.

 

During the year ended December 31, 2014, we did not drill any dry development wells. We did drill two gross (0.53 net) productive exploratory wells. We drilled 3 dry exploratory wells (1.50 net). We drilled 2 gross productive development wells (2.00 net wells).

 

Present Activities

 

We are currently drilling 1 gross (0.9485 net) exploratory wells. Our other current activities consist of recompleting one gross exploratory well (0.075 net well) and 1 gross development wells (0.0096189 net wells). We completed one gross exploratory well (0.03 net well) on March 17, 2015, which is currently in production in Sanpete County, Utah.

 

Oil and Gas Properties, Wells, Operations and Acreage

 

Productive Wells

 

Richfield, the Company acquired by Stratex, started acquiring properties in January 2009. Stratex began acquiring properties in 2012. Since that time, the combined companies have focused on acquiring leases and developing minimal field production in order to maintain our leases. Subject to permitting and adequate financing, we plan to continue to develop each field and commence drilling or complete additional wells over the next two years.

 

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The following table summarizes, as of March 31, 2015, our producing, shut-in, saltwater disposal wells and wells currently in the drilling or completion stage of development in Texas, Montana, Colorado, Kansas, Oklahoma, Utah and North Dakota.

 

Producing   Shut-In   SWD   Drill/Comp(3) 
Gross(1)   Net(2)   Gross(1)   Net(2)   Gross(1)   Net(2)   Gross(1)   Net(2) 
 55    15.74    19    17.59    9    8.81    3    1.03 

 

(1) “Gross” is a well in which we own a working interest.

 

(2) “Net” is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.

 

Acreage

 

As of March 31, 2015, we owned leases in Texas, Montana, Colorado, Kansas, Utah and North Dakota. Information about the number of acres for our leases is shown below:

 

   Undeveloped(3)   Developed(4)   Total 
   Gross(1)   Net(2)   Gross(1)   Net(2)   Gross(1)   Net(2) 
Mid-Continent   1,466    1,442    720    708    2,186    2,151 
Texas   19,472    18,460    320    312    19,792    18,772 
Williston Basin   -    -    420    420    420    420 
Small Non-Operated   13,854    4,947    39,782    344    53,636    5,291 
Central Utah Overthrust   1,671    1,671    -    -    1,671    1,671 
Utah/Wyoming   26,893    6,997    400    16    27,293    7,013 
Total   63,355    33,517    41,642    1,800    104,997    35,317 

 

(1) “Gross” means the total number of acres in which we have a working interest.
   
(2) “Net” means the aggregate number of acres based on our percentage working interests.
   
(3) “Undeveloped” means acreage encompassing those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas.
   
(4) “Developed” means acreage assignable to productive wells

 

Acreage Expirations

 

Our mineral leases are subject to expiration if we do not commence development operations that result in production within a proscribed term. Each of the leases relating to undeveloped acreage summarized below will expire at the end of its term unless we renew the lease, initiate development operations or establish production from the acreage. While we expect to establish production from most of our properties or exercise our option to extend prior to expiration of the applicable lease term, there can be no guarantee we can do so. If we are unable to establish production on our leased acreage, the cost to renew leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. The leases set to expire during the years ending December 31, 2015, 2016 and 2017 are set forth below:

 

   Acreage Expirations 
Years Ended December 31,  Gross   Net 
2015   10,104    1,255 
2016   839    72 
2017   425    60 
Total   11,368    1,387 

 

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Our Production History and Costs of Production

 

The following table presents information about our produced oil volumes during the year ended December 31, 2014 compared to the year ended December 31, 2013. We did not produce natural gas during the years ended December 31, 2014 or 2013. As of December 31, 2014, we were selling oil from a total of 53 gross wells (approximately 15.61 net wells). All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.

 

   Years Ended 
   December 31, 
   2014   2013 
Net Production:        
Oil (Bbl)   13,594    8,051 
Natural Gas (MCF)   1,043    561 
Barrel of Oil Equivalent (Boe)   14,637    8,612 
           
Average Sales Price:          
Oil (per Bbl)  $80.01   $89.45 
           
Natural Gas (per Mcf)  $6.14   $2.97 
           
Average Production Costs:          
Oil (per Bbl)  $55.08   $32.74 

 

Delivery Commitments

 

We have not entered into any commitments for the sale of crude oil or natural gas. We have made arrangements with two refineries in Kansas for the delivery of our oil on a spot price basis.

 

Regulation of the Oil and Gas Industry

 

Our operations are substantially impacted by U.S. federal, state and local laws and regulations. In particular, oil and gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or plan to own or operate properties for oil and gas production have statutory provisions regulating the exploration for and production of oil and gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and gas wells, as well as regulations that generally prohibit the venting or flaring of gas and that impose certain requirements regarding the ratability or fair appointment of production from fields and individual wells.

 

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Failure to comply with applicable laws and regulations can result in substantial penalties and the regulatory burden on the industry in the U.S. and increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the oil and gas industry are regularly considered by Congress, states within the U.S., the Federal Energy Regulatory Commission (“FERC”), and U.S. federal and state courts. We cannot predict when or whether any such proposals may become effective or the costs of complying therewith.

 

Regulation of Transportation and Sales of Oil

 

Sales of crude oil, condensate and gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could re-enact price controls in the future.

 

Sales of crude oil will be affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index ceiling slightly, effective July 2001. Following the FERC’s five-year review of the indexing methodology, the FERC issued an order in 2006 increasing the index ceiling.

 

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 operations in any way that is of material difference from those of competitors who are similarly situated.

 

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 similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to similarly situated competitors.

 

Regulation of Transportation and Sales of Natural Gas

 

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”), and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could re-enact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

 

Regulation of Production

 

Our oil and natural gas exploration, production and related operations are subject to extensive regulations promulgated by federal, state and local authorities. For example, Utah, Kansas and Oklahoma require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements related to the exploration and production of oil and natural gas. Such jurisdictions may also have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations may be to limit the amount of oil and natural gas that we can produce from and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended and reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with regulations and may have a material adverse effect on our financial condition and results of operations. Moreover, each jurisdiction generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids.

 

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The failure to comply with these rules and regulations can result in substantial penalties. Competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

 

Other Federal Laws and Regulations Affecting the Industry

 

The Energy Policy Act of 2005 (the “EPAct2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the U.S. energy industry. Among other matters, EPAct2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct2005 provides the FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as other non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, as described below. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Should we fail to comply with applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.

 

FERC Market Transparency Rules

 

On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.5 Million British Thermal Units (“MMBTU”) of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. In order to provide respondents time to implement the new regulations contained in Order No. 704, the FERC extended the deadline for calendar year 2009 until October 1, 2010. The deadline to report for calendar year 2010 and subsequent years remains May 1 of the following calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.

 

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action in a material way that would be different than similarly situated competitors.

 

Environmental, Health and Safety Regulation

 

Exploration, development and production operations will be subject to various federal, state and local laws and regulations governing health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and gas drilling and production; restrict the way we handle or dispose of wastes; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all operations in affected areas.

 

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These laws and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The complexity and comprehensive nature of the environmental laws and regulations affecting the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal, cleanup and remediation requirements for the oil and gas industry could have a significant impact on operating costs.

 

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, particularly under air quality and water quality laws and standards, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements, could have a material adverse effect on our operations and financial position. Of particular note, the U.S. Environmental Protection Agency (“EPA”) has recently made the enforcement of environmental laws in the oil and gas exploration and production sector a formal enforcement priority. Increased compliance costs may not be able to be passed on to purchasers or customers. Moreover, accidental releases or spills may occur in the course of operations, and we cannot assure prospective investors 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.

 

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

 

Endangered Species

 

The federal Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. We believe our operations are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA. Under the September 9, 2011 settlement, the federal agency is required to make a determination on listing of the species as endangered or threatened over the next six years, through the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

 

Hazardous Substances and Waste

 

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where a release occurred and entities that disposed or arranged for the disposal for the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up hazardous substances that have been released into the environment, for damages to natural resources, and for the cost of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in respect to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. Our operations will generate materials that may be regulated as hazardous substances.

 

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We anticipate that our operations will also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (the “RCRA”), and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We anticipate that our operations will generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes.

 

We own or lease and, in connection with future acquisitions, we anticipate that we will acquire, properties that have been used for numerous years to explore and produce oil and gas. Hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties may have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination.

 

Air Emissions

 

The Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and gas projects.

 

On August 15, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. These standards require that prior to January 1, 2015, owners/operators reduce volatile organic compounds emissions from natural gas not sent to the gathering line during well completion either by flaring or by capturing the gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells as well as existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions.

 

Climate Change

 

In response to findings that emissions of carbon dioxide and certain other gases may be contributing to warming of the earth’s atmosphere, the Environmental Protection Agency (“EPA”) has adopted regulations under existing provisions of the federal Clean Air Act that would require a reduction in emissions of greenhouse gases (“GHG”) from motor vehicles. The EPA has asserted that the final motor vehicle GHG emission standards also triggered construction and operating permit requirements for stationary sources. Thus, on June 3, 2010, the EPA issued a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, on November 8, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage and distribution activities. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year are now required to report annual GHG emissions to the EPA, with the first report for emissions occurring in 2011 due on September 28, 2012. Our operations did not result in emissions exceeding the threshold for reporting, and as a result, we are not required to submit a report to the EPA. In the event our operations involve venting or flaring natural gas in the future, or otherwise result in CO2 emissions exceeding the threshold for reporting, we intend to monitor our emissions and submit reports to the EPA. In addition, both houses of Congress have 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. Any laws or regulations that may be adopted to restrict or reduce emissions of U.S. greenhouse gases could require the Company to incur increased operating costs such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements, and could have an adverse effect on demand for oil and natural gas.

 

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Water Discharges

 

The Federal Water Pollution Control Act, as amended, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the U.S. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

 

The Oil Pollution Act of 1990, as amended, (the “OPA”), which amends the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the U.S.

 

Hydraulic Fracturing

 

We expect to develop certain of our properties in Kansas, Utah, Colorado, North Dakota and Montana utilizing horizontal drilling and hydraulic fracturing. Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices, (i.e., use of diesel, kerosene and similar compounds in the fracturing fluid). Also, in May 2012, the U.S. Department of the Interior’s Bureau of Land Management, or BLM, proposed regulations that would require public disclosure of the chemicals used in hydraulic fracturing and impose certain permitting, testing and other requirements on such operations on federal lands. However, on January 18, 2013, the BLM announced that it would be revising and re-proposing these regulations at a later date. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Certain states and municipalities in which we operate have adopted, or are considering adopting, regulations that have imposed, or that could impose, more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state level, such legal requirements could cause project delays and make it more difficult or costly for the Company to perform fracturing to stimulate production of oil and natural gas. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. In addition, if hydraulic fracturing is regulated at the federal level, the Company’s fracturing activities could become subject to additional permit requirements, reporting requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce in commercial quantities.

 

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Employee Health and Safety

 

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (the “OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

 

We are committed to conducting our activities in a manner that will safeguard the health and safety of our employees, contractors and the general public. Our management is responsible for providing and maintaining a safe work environment with proper procedures, training, equipment and programs to ensure that work is performed in compliance with accepted and legislated standards. Employees share the responsibility to work in a manner which safeguards themselves with equal concern for co-workers, contractors and the general public. We will administer a comprehensive health and safety program, which will include corporate commitment, risk assessment and monitoring, capability, development, emergency response plans and systems for incident reporting, tracking and investigation.

 

ITEM 1A.RISK FACTORS

 

Our business operations and the implementation of our business strategy are subject to significant risks inherent in our business, including, without limitation, the risks and uncertainties described below. The occurrence of any one or more of the risks or uncertainties described below could have a material adverse effect on our consolidated financial condition, results of operations and cash flows and could cause actual results to differ materially from the results contemplated by the forward-looking statements contained in this annual report. While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, operations, industry, financial position and financial performance in the future. Because of the following risks and uncertainties, as well as other variables affecting our operating results, past financial performance should not be considered a reliable indicator of future performance and historical trends may not be consistent with results or trends in future periods. Our consolidated financial statements and the notes thereto and the other information contained in this annual report should be read in connection with the risk factors discussed below.

 

Risks Related to Our Business

 

Our independent auditors question our ability to continue as a going concern.

 

Our independent registered public accounting firm’s reports on our financial statements for the years ended December 31, 2014 and 2013 states that there is substantial doubt about our ability to continue as a going concern due to substantial losses from operations, negative working capital, negative cash flow, and the lack of sufficient capital, as of the date the report was issued, to support our planned capital expenditures to continue our drilling programs.

 

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We can provide no assurance that we will be able to obtain sufficient additional financing that we need to develop our properties and alleviate doubt about our ability to continue as a going concern. If we are able to obtain sufficient additional financing proceeds, we cannot be certain that this additional financing will be available on acceptable terms, if at all. To the extent we raise additional funds by issuing equity securities, our stockholders may experience significant dilution. Any debt financing, if available, may involve restrictive covenants that impact our ability to conduct business. Inclusion of a “going concern qualification” in the report of our independent auditors or any future report may have a negative impact on our ability to obtain financing and may adversely impact our stock price.

 

We have a limited operating history, and we expect that operating losses will continue for the foreseeable future.

 

Our losses from continuing operations were $13,988,215 in 2014 and $5,224,915 in 2013. No assurance can be given that we will achieve profitability or positive cash flows from our operations in the future. Our current cash balance, together with cash anticipated to be provided by operations, will not be sufficient to satisfy our anticipated cash requirements for normal operations and capital expenditures for the foreseeable future. There can be no assurance that our business operations will prove to be successful in the long-term. Our future operating results will depend on many factors, including:

 

  our ability to raise adequate working capital;
     
  success of our development and exploration;
     
  demand for and prices of oil and natural gas;
     
  our ability to obtain required regulatory approvals;
     
  the 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 oil or natural gas in a highly competitive and speculative environment while maintaining quality and controlling costs.

 

We must successfully manage the factors stated above, many of which are beyond our control, as well as continue to develop ways to enhance our production efforts to successfully execute our business plan and achieve profitable operations in the future. If our properties do not attain sufficient revenues or do not achieve profitable operations, our business may fail.

 

We require significant additional capital to continue operating as a going concern, which we may not obtain.

 

We currently have a substantial working capital deficit and require significant additional capital in the near term to continue operations. We must secure additional funding to pay our current liabilities, continue as a going concern and execute our business plan, which requires us to make large capital expenditures for the exploration and development of our oil and natural gas properties. We will require significant additional funding during the next twelve months to fund development costs, corporate overhead, payment of debt and payment of all other of our contractual obligations. Since our inception, we have financed our cash flow requirements through the issuance of common and preferred stock, short and long-term borrowings and selling working interests in our oil and natural gas properties for cash and services. Our cash and cash equivalents will continue for the foreseeable future to be depleted by our ongoing development efforts as well as our general and administrative expenses. Until we are in a position to generate significant revenues, we will continue to depend on cash provided by equity financings and debt financings or credit facilities, and sales of working interests in our properties, in order to continue operating as a going concern. Furthermore, in the event that our plans change or our assumptions change or prove inaccurate, we could be required to seek additional financing in greater amounts than is currently anticipated.

 

There can be no assurance that financing will be available in amounts or terms that are acceptable to us, if at all. If sufficient capital resources are not available, we might be forced to cease operations or significantly curtail drilling and other activities, including our plans to acquire additional acreage positions and development activities, or we might be forced to sell assets on an untimely or unfavorable basis.

 

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Economic conditions continue to be weak and global financial markets continue to experience significant volatility and liquidity challenges. These conditions may make it more difficult for us to obtain financing. Even if we are successful in obtaining financing on acceptable terms, issuing additional equity securities to satisfy our financial requirements could cause substantial dilution to our existing stockholders and may result in a change of control. Raising additional debt financing could lead to:

 

  a substantial portion of operating cash flow being dedicated to the payment of principal and interest;
     
  increased vulnerability to competitive pressures and economic downturns; and
     
  restrictions on our operations.

 

Competition in the oil and gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do, which may adversely affect our ability to compete.

 

Competition relating to all aspects of the oil and gas industry is intense. We will actively compete for capital, skilled personnel, access to rigs and other equipment, access to processing facilities and pipeline and refining capacity and in all other aspects of our operations with a substantial number of other organizations, many of which will have greater technical and financial resources. Our competitors who possess greater technical and financial resources than we do may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit.

 

We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition would be adversely affected.

 

In general, production from oil and gas properties declines over time as reserves are depleted, with the rate of decline depending on reservoir characteristics. If we are not successful in our exploration and development activities or in acquiring additional properties containing proved reserves, our proved reserves will decline as reserves are produced. Our future oil and gas production is highly dependent upon our ability to economically find, develop or acquire reserves in commercial quantities.

 

To the extent cash flow from operations is reduced, either due to a decrease in prevailing prices for oil and gas or an increase in exploration and development costs, and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be impaired. Even with sufficient available capital, our future exploration and development activities may not result in additional proved reserves, and we might not be able to drill productive wells at acceptable costs.

 

Our oil and gas reserves, production, and cash flows to be derived therefrom are highly dependent on our ability to successfully acquire or discover new reserves. Without the continual addition of new reserves, any existing reserves we may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in our reserves will depend not only on our ability to develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or projects. There can be no assurance that our future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and gas. Competition may also be presented by alternate fuel sources.

 

Our projects may be adversely affected by risks outside of our control including labor unrest, civil disorder, war, subversive activities or sabotage, fires, floods, explosions or other catastrophes, epidemics or quarantine restrictions.

 

Our inability to control the inherent risks of acquiring businesses and assets could adversely affect our operations.

 

Acquisitions are a key element of our business strategy. We cannot assure you that we will be able to identify and acquire acceptable properties or businesses on terms favorable to us in the future. We may be required to incur substantial indebtedness to finance future acquisitions. Such additional debt service requirements may impose a significant burden on our results of operations and financial condition. We cannot assure you that we will be able to successfully consolidate the operations and assets we acquire with our existing business. The integration of acquired operations and assets may require substantial management effort, time and resources and may divert management’s focus from other strategic opportunities and operational matters. Acquisitions may not perform as expected when the transaction was consummated and may be dilutive to our overall operating results. In addition, our management may not be able to effectively manage our increased size or operate a new line of business.

 

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We are an emerging growth company, and have elected to delay the adoption of new or revised accounting standards until those standards apply to private companies. As a result of this election, our financial statements may not be comparable to companies that comply with public company effective dates.

 

We qualify as an “emerging growth company,” as defined in Section 2(a) of the Securities Act of 1933, as amended, or the Securities Act, as modified by the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. As such, we are permitted to rely on exemptions from various reporting requirements including, but not limited to, the requirement to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act of 2002, and the requirement to submit certain executive compensation matters to shareholder advisory votes such as “say on pay” and “say on frequency.”

 

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to take advantage of the benefits of this extended transition period. Our financial statements may therefore not be comparable to those of companies that comply with such new or revised accounting standards.

 

We will remain an emerging growth company up to the fifth anniversary of our first registered sale of common equity securities, or until the earliest of (a) the last day of the first fiscal year in which our annual gross revenues exceed $1 billion, (b) the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended, or the Exchange Act, which would occur if the market value of our common stock held by non-affiliates exceeds $700 million as of the last business day of our most recently completed second fiscal quarter, or (c) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period.

 

During the period in which we qualify as an emerging growth company and elect to provide more limited disclosure as allowed by the JOBS Act, we cannot predict if investors will find our common stock less attractive as a result. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

 

Substantially all of our producing properties and operations are located in the west and mid-west of the United States, making us vulnerable to risks associated with operating in two major geographic areas.

 

All of our proved reserves and all of our expected oil and gas production are located in Oklahoma, Kansas, Utah and Wyoming. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or gas produced from the wells in these areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas which may cause these conditions to occur with greater frequency or magnify the effect of these conditions on us. Due to the concentrated nature of our portfolio of properties, a number of these properties could experience many of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

 

If ultimate production associated with these properties is less than our estimated reserves, or changes in pricing, cost or recovery assumptions in the area results in a downward revision of any estimated reserves in these properties, our business, financial condition or results of operations could be adversely affected.

 

Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities.

 

The level of activity in the oil and gas industry in the west and mid-west of the U.S. is influenced by seasonal weather patterns. In some climates, drilling and oil and gas activities cannot be conducted as effectively during the winter months. In other climates, a mild winter or wet spring may result in limited access and, as a result, reduced operations or a cessation of operations. Municipalities and state transportation departments enforce road bans that restrict the movement of drilling rigs and other heavy equipment during periods of wet weather, thereby reducing activity levels. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for our oil and gas.

 

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Severe weather conditions limit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our oil and gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

 

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

 

We expect to develop certain of our properties in Kansas Utah, Colorado, North Dakota and Montana utilizing horizontal drilling and hydraulic fracturing. The U.S. Congress is considering legislation that would amend the federal Safe Drinking Water Act by repealing an exemption for the underground injection of hydraulic fracturing fluids near drinking water sources. Hydraulic fracturing is an important and commonly used process for the completion of crude oil and natural gas wells in shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate production. Sponsors of the legislation have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the legislation could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The legislation also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information 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. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of any federal or state legislation or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process 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.

 

Acreage must be drilled before lease expiration, generally within two 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.

 

Our mineral leases are subject to expiration if we do not commence development operations that result in production within a proscribed term. Each of the leases relating to undeveloped acreage summarized below will expire at the end of its term unless we renew the lease, initiate development operations or establish production from the acreage. While we expect to establish production from most of our properties or exercise our option to extend prior to expiration of the applicable lease term, there can be no guarantee we can do so. If we are unable to establish production on our leased acreage, the cost to renew leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. The leases set to expire during the years ending December 31, 2015, 2016 and 2017 are set forth below:

 

   Acreage Expirations 
Years Ended December 31,  Gross   Net 
2015   10,104    1,255 
2016   839    72 
2017   425    60 
Total   11,368    1,387 

 

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We depend on drilling partners for the successful development and exploitation of certain oil and gas properties in which we hold an interest.

 

We do not operate all oil and gas properties in which we hold an interest. As a result, we have limited influence and control over the operation of properties we do not operate. The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond our control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of appropriate technology. If our drilling partners are unable or unwilling to perform, our financial condition and results of operation could be adversely affected.

 

The loss of our directors or key management and technical personnel or our inability to attract and retain experienced technical personnel could adversely affect our ability to operate our business.

 

We depend, to a large extent, on the efforts and continued employment of our senior management team. At this time, the loss of certain key individuals could adversely affect our business operations. Successful exploration, development and commercialization of oil and gas interests rely on a number of factors, including the technical skill of the personnel involved. Our success will depend, in part, on the performance of our key managers and consultants. Failure to attract and retain managers, consultants and other key personnel with the necessary skills and experience could have a materially adverse effect on our growth and profitability.

 

We may not be insured against all of the operating hazards to which our business is exposed.

 

The ownership and operation of oil and gas wells, pipelines and facilities involve a number of operating and natural hazards which may result in blowouts, environmental damage and other unexpected or dangerous conditions resulting in damage to our properties and potential liability to third parties for property damage, environmental damage or personal injury. We intend to employ prudent risk-management practices and maintain suitable liability insurance, where available. We may become liable for damages arising from such events against which we cannot insure or against which we may elect not to insure because of high premium costs or other reasons. Costs incurred to repair such damage or pay such liabilities could have a material adverse effect on us, our operations and financial condition.

 

Our properties may be subject to title claims in the future.

 

Title to oil and gas interests is often not capable of conclusive determination without incurring substantial expense. While it is our practice to make appropriate inquiries into the title of properties and other development rights we acquire, 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 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.

 

We may be exposed to third-party credit risk and defaults by third parties could adversely affect us.

 

We are or may be exposed to third-party credit risk through our contractual arrangements with our current or future customers, joint venture partners, marketers of our petroleum production and other parties. In the event such entities fail to meet their contractual obligations to us, such failures could have a material adverse effect on us and our funds from operations.

 

The global economy has not fully recovered and unforeseen events may negatively impact our financial condition.

 

Market events and conditions including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions caused significant volatility to commodity prices over the last few years. The credit crisis and related turmoil in the global financial system may adversely impact our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we would need to raise capital, which could adversely affect our ability to react to changing economic and business conditions. If the economic climate in the U.S. or the world generally deteriorates further, demand for petroleum products could diminish and prices for oil and gas could decrease, which could adversely impact our results of operations, liquidity and financial condition.

 

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Risks Related to our Industry

 

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

 

The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

 

  changes in regional, national and/or global supply and demand for oil and natural gas;
     
  the actions of the Organization of Petroleum Exporting Countries;
     
  the price and quantity of imports of foreign oil and natural gas;
     
  political and economic conditions, including embargoes, in crude oil-producing countries or affecting other crude oil-producing activity;
     
  the level of regional, national and/or global oil and natural gas exploration and production activity;
     
  the level of regional, national and/or global oil and natural gas inventories;
     
  weather conditions;
     
  technological advances affecting energy consumption;
     
  domestic and foreign governmental regulations and tax laws;
     
  proximity and capacity of oil and natural gas pipelines and other transportation facilities;
     
  the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and
     
  the price and availability of alternative fuels.

 

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. Our reserve base is heavily weighted towards oil producing properties many of which are utilizing or will utilize secondary recovery methods characterized by higher operating costs than many other types of fields, such as oil fields in their primary recovery stage or natural gas fields. The higher operating costs associated with many of our oil fields will make our profitability more sensitive to oil price declines. Lower prices will also negatively impact the value and quantity of our proved and unproved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

 

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

 

Oil operations involve many risks, many of which are beyond our control. Our long-term commercial success depends on our ability to find, acquire, finance, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, our existing reserves and the production therefrom will decline over time as such reserves are exploited. A future increase in our reserves will depend not only on our ability to explore and develop our existing properties, but also on our ability to select and acquire suitable producing properties or projects. We can give no assurance that we will continue to locate satisfactory properties for acquisition or participation. Moreover, if we identify suitable properties for acquisition or participation, we may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. We have no assurance that we will discover or acquire further commercial quantities of oil and natural gas.

 

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Future oil and natural 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 imposed by or resulting from compliance with regulatory requirements;
     
  pressure or irregularities in geological formations;
     
  shortages of or delays in obtaining equipment and qualified personnel;
     
  equipment failures or accidents;
     
  adverse weather conditions;
     
  reductions in oil and natural gas prices;
     
  oil and natural gas property title problems; and
     
  market limitations for oil and natural gas.

 

While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

 

Our oil exploration, development and production activities are subject to all the risks and hazards typically associated with such activities, including hazards such as fire, explosion, blowouts, cratering, sour natural gas releases and spills. Each of these hazards could result in personal injury or death, or substantial damage to oil and natural gas wells, production facilities, other property and the environment. In accordance with industry practice, we are not fully insured against all of these risks, nor are all such risks insurable. Although we maintain liability insurance in an amount that is considered consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect upon our financial condition. Our oil and natural gas production activities are also subject to all the risks typically associated with such activities, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks could have a material adverse effect on our future results of operations, liquidity and financial condition.

 

Upon a commercial discovery, market conditions or operational impediments may hinder our access to oil and natural gas markets or delay its production.

 

Upon a commercial discovery, the marketability of our production depends in part upon the availability, proximity and capacity of pipelines, trucks, railways, storage, gathering systems and processing facilities. This dependence is heightened where this infrastructure is less developed. Therefore, if drilling results are positive in certain areas, we would need to build production facilities to handle the potential volume of oil and natural gas produced. We might be required to shut in wells, at least temporarily, due to the inadequacy or unavailability of transportation facilities. If that were to occur, we would be unable to realize revenue from those wells until we could make arrangements to deliver production to market.

 

Our ability to produce and market oil and natural gas is affected and also may be harmed by:

 

  the lack of transportation, storage, pipeline transmission facilities or carrying capacity;
     
  government regulation of oil and natural gas production;
     
  government transportation, tax and energy policies;
     
  changes in supply and demand; and
     
  general economic conditions.

 

Shortages of rigs, equipment, supplies and personnel could delay or otherwise adversely affect our cost of operations or our ability to operate according to our business plan.

 

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment and qualified personnel in the particular areas where such activities will be conducted. Due to drilling activity increases, a general shortage of drilling rigs, equipment, supplies and personnel has developed. As a result, the costs and delivery times to oil and natural gas operators have sharply increased and could do so again. The demand for and wage rates of qualified drilling rig crews generally rise in response to the increasing number of active rigs in service and could increase sharply in the event of a shortage. Shortages of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development operations, which could have a material adverse effect on our business, financial condition and results of operations.

 

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Reserve estimates are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

 

The information concerning reserves and associated cash flow set forth in this annual report represents estimates only. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available geological, geophysical, production and engineering data and many assumptions, including assumptions relating to economic factors and other factors beyond our control. The extent, quality and reliability of this technical data can vary. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. In general, estimates of economically recoverable oil reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, including the following, all of which may vary from actual results:

 

  historical production from the properties,
     
  production rates,
     
  ultimate reserve recovery,
     
  timing and amount of capital expenditures,
     
  marketability of oil and natural gas,
     
  royalty rates, and
     
  the assumed effects of regulation by governmental agencies and future operating costs.

 

For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom prepared by different engineers, or by the same engineers at different times, may vary. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from estimates thereof and such variations could be material. Further, evaluations are based, in part, on the assumed success of the exploitation activities intended to be undertaken in future years. The reserves and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent that such exploitation activities do not achieve the level of success assumed in the evaluation.

 

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material. Many of our producing wells have a limited production history and thus there is less historical production on which to base the reserves estimates. In addition, a significant portion of our reserves may be attributable to a limited number of wells and, therefore, a variation in production results or reservoir characteristics in respect of such wells may have a significant impact upon our reserves.

 

In accordance with applicable disclosure regulations of the SEC, Pinnacle has used forecast price and cost estimates in calculating reserve quantities. Actual future net cash flows will be affected by other factors such as actual production levels and timing, actual prices we receive for oil and natural gas, actual cost of development and production expenditures, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. Actual production and cash flows derived therefrom will vary from the estimates contained in the 2014 Pinnacle Reserve Report, and such variations could be material. The 2014 Pinnacle Reserve Report is based in part on the assumed success of activities we intend to undertake in future years. The reserves and estimated cash flows to be derived therefrom contained in the 2014 Pinnacle Reserve Report will be reduced to the extent that such activities do not achieve the level of success assumed in the 2014 Pinnacle Reserve Report.

 

The 2014 Pinnacle Reserve Report sets forth estimates of our reserves as of December 31, 2014 and has not been updated and thus does not reflect changes in our resources since that date.

 

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If our costs of production continue to exceed the estimated costs contained in the 2014 Pinnacle Reserve Report, our affected properties’ reserves will be removed.

 

We have experienced high costs of production in the initial operation of our wells. If this high cost continues above the estimated costs contained in the 2014 Pinnacle Reserve Report, extraction of hydrocarbons from our affected properties may not be economically viable, in which case the affected reserves would be removed from our reserve report.

 

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

 

Our prospects are in various stages of evaluation. There is no way to predict with certainty in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies, and the study of producing fields in the same area, will not enable us to know conclusively before drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercially viable quantities. Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.

 

We are subject to complex laws and regulations, including environmental regulations, that can have a material adverse effect on the cost, manner and feasibility of doing business.

 

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government and may be amended from time to time. Our operations may require licenses from various governmental authorities. There can be no assurance that we will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at our projects.

 

The oil and gas industry is subject to regulation, enforcement and intervention by governments in such matters as:

 

  awarding and licensing of exploration and production interests;
     
  imposition of specific drilling obligations, and requirements (including drilling bonds and permits for drilling, water discharge and disposal, air quality and noise levels);
     
  imposition of pollution controls and environmental protection;
     
  regulation of health and safety effects and offshore activity and operations;
     
  control over the development, decommissioning and abandonment of fields (including restrictions on production);
     
  imposition of reporting obligations;
     
  regulation of prices, taxes, royalties and exploration for oil and natural gas;
     
 

cancellation of contract rights; and

     
  imposition of rights-of-way and easements.

 

Under these laws, we could be subject to claims for personal injury or property damages, including natural resource damages, which may result from the impacts of our operations. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Additionally, such regulation may be changed from time to time in response to economic or political conditions. The implementation of new legislation or regulations or the modification of existing legislation or regulations affecting the oil and gas industry could reduce demand for crude oil, increase costs and may have a material adverse impact on us. Export sales are subject to the authorization of government agencies and the corresponding governmental policies of foreign countries.

 

Our operations expose us to substantial costs and liabilities with respect to environmental matters.

 

The oil and gas industry is subject to environmental regulations pursuant to local, state and federal legislation. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with our drilling and production activities, limit or prohibit drilling activities within certain lands lying within wilderness and other protected areas, and impose substantial liabilities for pollution that may result from our operations. Under existing environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the release resulted from our operations, or our operations were in compliance with all applicable laws at the time they were performed. Should we be unable to fully fund the cost of remedying an environmental liability, we might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy. Environmental legislation is evolving in a manner expected to 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. Although we believe that we are in material compliance with current applicable environmental regulations, we can give no assurance that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect our financial condition, results of operations or prospects.

 

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Our current development plans include drilling several horizontal wells and utilizing hydraulic fracturing, which is subject to a range of applicable federal, state and local laws. Hydraulic fracturing operations are designed and operated to minimize the risk, if any, of subsurface migration of hydraulic fracturing fluids and spillage or mishandling of hydraulic fracturing fluids. However, a proven case of subsurface migration of hydraulic fracturing fluids or a case of spillage or mishandling of hydraulic fracturing fluids during these activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including environmental remediation, depending on the circumstances of the underground migration, spillage, or mishandling, the nature and scope of the underground migration, spillage, or mishandling, and the applicable laws and regulations. In addition, the practice of hydraulically fracturing formations to stimulate the production of natural gas and oil has come under increased scrutiny from federal and state governmental authorities. New regulations concerning hydraulic fracturing could be passed that would materially adversely affect our affect our ability to economically explore and develop our oil and natural gas properties.

 

Possible regulation related to climate change and global warming could have a negative impact on our business.

 

Federal and state governments are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from certain stationary sources common in our industry. The EPA has made findings and issued proposed regulations that could lead to the imposition of restrictions on greenhouse gas emissions from certain stationary sources and that could require us to establish and report an inventory of greenhouse gas emissions. In addition, the U.S. Congress is in the process of considering various bills that would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. Such a program, if enacted, could require phased reductions in greenhouse gas emissions over a number of years and could result in the issuance of a declining number of tradable allowances to sources that emit greenhouse gases into the atmosphere. Legislation and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for our oil and natural gas. Potential increases in operating costs could include new or increased costs to obtain permits, operate and maintain equipment and facilities, install new emission controls on equipment and facilities, acquire allowances to authorize greenhouse gas emissions, pay taxes related to greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil and natural gas.

 

Delays in business operations may reduce cash flows and subject us to credit risks.

 

In addition to the usual delays in payments by purchasers of oil and natural gas to us or to the operators, and the delays by operators in remitting payment to us, payments between these parties may be delayed due to restrictions imposed by lenders, accounting delays, delays in the sale of delivery of products, delays in the connection of wells to a gathering system, adjustment for prior periods, or recovery by the operator of expenses incurred in the operation of the properties. Any of these delays could reduce the amount of cash flow available for our business in a given period and expose us to additional third-party credit risks.

 

Alternatives to and changing demand for petroleum products.

 

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and energy generation devices could reduce the demand for crude oil and other liquid hydrocarbons. We cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

41
 

 

Proposals to increase U.S. federal income taxation of independent producers may negatively affect our results.

 

Recently, U.S. federal budget proposals would potentially increase and accelerate the payment of federal income taxes of independent producers of oil and natural gas. Proposals that would significantly affect us would repeal the expensing of intangible drilling costs, repeal the percentage depletion allowance and increase the amortization period of geological and geophysical expenses. These changes, if enacted, will make it more costly to explore for and develop oil and natural gas resources. We are unable to predict whether any changes, or other proposals to such laws, ultimately will be enacted. Any such changes could negatively impact our cash flows and future operating results.

 

Risks Related to our Common Stock

 

Our directors and executive officers beneficially own a significant amount of our common stock and will be able to exercise significant influence on matters requiring stockholder approval.

 

Alan D. Gaines, our Chairman of the Board of Directors owned approximately 4.94% of our common stock as of March 31, 2015, Stephen Funk, our President and Chief Executive Officer beneficially owned approximately 5.41% of our common stock as of March 31, 2015, Michael Thurz, our Chief Administrative Officer, owned approximately 1.26% of our common stock as of March 31, 2015 and our directors and executive officers collectively beneficially owned approximately 13.6% of our common stock as of March 31, 2015. Consequently, Messrs. Gaines, Funk and Thurz individually, and our directors and executive officers as a group are able to exert significant influence over the election of directors and the outcome of most corporate actions requiring stockholder approval which may have the effect of delaying or precluding a third party from acquiring control of us.

 

Our Common Stock is quoted on the OTCBB, which may have an unfavorable impact on our stock price and liquidity.

 

Our common stock is quoted on the OTCBB (“OTCBB”). The OTCBB is a significantly more limited market than the national securities exchanges. The OTCBB is an inter-dealer market which is much less regulated than the major exchanges, which may subject our common stock to more abuses, volatility and shorting. There is currently no broadly followed and established public trading market for our common stock. An established public trading market may never develop or be maintained. Active trading markets generally result in lower price volatility and more efficient execution of buy and sell orders. Absence of an active trading market reduces the level of liquidity available to the holders of our common stock.

 

It may not be possible for a shareholder to sell its common stock within any particular time period, for an acceptable price, or at all. There is no certainty that a holder of common stock will be able to identify a buyer for common stock or realize any monetary value whatsoever from a sale thereof.

 

Our common stock is considered highly speculative and there is no certainty that our common stock will continue to be quoted for trading on the OTCBB or on any other form of quotation system or securities exchange, and even if the common stock were to be listed on a quotation system or securities exchange senior to the OTCBB, the common stock would continue to be subject to the resale restrictions and other limitations described above.

 

The application of the “penny stock” rules could adversely affect the market price of our common stock and increase your transaction costs to sell those shares.

 

Our common stock may be subject to the “penny stock” rules adopted under Section 15(g) of the Exchange Act. The penny stock rules apply to issuers whose common stock does not trade on a national securities exchange and trades at less than $5.00 per share, or that have a tangible net worth of less than $5,000,000 ($2,000,000 if the company has been operating for three or more years). The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from those rules, to deliver a standardized risk disclosure document prepared by the SEC that contains the following information:

 

 a description of the nature and level of risk in the market for penny stocks in both public offerings and secondary trading;
   
 a description of the broker’s or dealer’s duties to the customer and of the rights and remedies available to the customer with respect to violation to such duties or other requirements of securities laws;
   
 a brief, clear, narrative description of a dealer market, including “bid” and “ask” prices for penny stocks and the significance of the spread between the “bid” and “ask” prices;
   
 a toll free telephone number for inquiries on disciplinary actions;
   
 definitions of any significant terms in the disclosure document or in the conduct of trading in penny stocks; and
   
 such other information and is in such form (including language, type, size and format), as the SEC shall require by rule or regulation.

 

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Prior to effecting any transaction in a penny stock, the broker-dealer also must provide the customer with the following information:

 

 bid and offer quotations for the penny stock;
   
 compensation of the broker-dealer and our salesperson in the transaction;
   
 number of shares to which such bid and ask prices apply, or other comparable information relating to the depth and liquidity of the market for such stock; and
   
 monthly account statements showing the market value of each penny stock held in the customer’s account.

 

The penny stock rules further require that, prior to a transaction in a penny stock not otherwise exempt from those rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written acknowledgment of the receipt of a risk disclosure statement, a written agreement to transactions involving penny stocks and a signed and dated copy of a written suitability statement.

 

Due to the requirements of the penny stock rules, many broker-dealers have decided not to trade penny stocks. As a result, the number of broker-dealers willing to act as market makers in such securities is limited. If we remain subject to the penny stock rules for any significant period, it could have an adverse effect on the market, if any, for our securities. Moreover, if our securities are subject to the penny stock rules, investors will find it more difficult to dispose of our securities.

 

We have the right to, and expect to, issue additional equity or equity-linked securities without stockholder approval, which would dilute the percentage ownership of our stockholders and depress the market price of shares of our common stock.

 

We have authorized capital of 750,000,000 shares of common stock and 400 shares of preferred stock. As of March 31, 2015, 120,737,337 common shares and no preferred shares were issued and outstanding. In addition, as of March 31, 2015, we had outstanding warrants to purchase approximately 32,426,907 shares of our common stock, we had outstanding options to purchase approximately 15,350,000 shares of our common stock, and notes convertible into approximately 73,645,128 shares of our common stock. Our Board of Directors has authority, without action or vote of our shareholders, to issue all or part of the authorized but unissued shares. Any such issuance will dilute the percentage ownership of our shareholders, and may dilute the book value per share of our common stock.

 

Our operating results may fluctuate significantly, and these fluctuations may cause the price of our common stock to decline.

 

Our operating results will likely vary in the future primarily as the result of fluctuations in our revenues and operating expenses, including the coming to market of oil and natural gas reserves that we are able to discover and develop, expenses that we incur, the prices of oil and natural gas in the commodities markets and other factors. If our results of operations do not meet the expectations of current or potential investors, the price of our common stock may decline.

 

Because we have never paid a common stock dividend and will not pay any dividends for the foreseeable future, stockholders must look solely to appreciation of our common stock to realize a gain on their investments.

 

We have never paid a dividend nor made a distribution on our common stock. Further, we may never achieve a level of profitability that would permit payment of dividends or making other forms of distributions to common stockholders. In any event, given the stage of our development, it will likely be a long period of time before we could be in a position to pay dividends or distributions to our investors. The payment of any future dividends will be at the sole discretion of the Board. In this regard, we currently intend to retain earnings to finance the expansion of our business and do not anticipate paying dividends in the foreseeable future. Accordingly, stockholders must look solely to appreciation of our common stock to realize a gain on their investment. This appreciation may not occur.

 

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If we were to issue preferred stock, the rights of holders of our common stock and the value of such common stock could be adversely affected.

 

Our Board of Directors is authorized to issue classes or series of preferred stock, without any action on the part of the stockholders. The Board of Directors also has the power, without stockholder approval, to set the terms of any such classes or series of preferred stock, including voting rights, dividend rights and preferences over the common stock with respect to dividends or upon the liquidation, dissolution or winding-up of our business and other terms. If we issue preferred stock in the future that has a preference over the common stock, with respect to the payment of dividends or upon liquidation, dissolution or winding-up, or if we issue preferred stock with voting rights that dilute the voting power of the common stock, the rights of holders of the common stock or the value of the common stock would be adversely affected.

 

If we are not the subject of securities analyst reports or if any securities analyst downgrades our common stock or our sector, the price of our common stock could be negatively affected.

 

Securities analysts may publish reports about us or our industry containing information about us that may affect the trading price of our common stock. In addition, if a securities or industry analyst downgrades the outlook for our stock or one of our competitors’ stock, the trading price of our common stock may also be negatively affected.

 

Future sales of our common stock by our existing stockholders may negatively impact the trading price of our common stock.

 

If a substantial number of our existing stockholders decide to sell shares of their common stock in the public market, the price at which our common stock trades could decline. Additionally, the public market’s perception that such sales might occur may also depress the price of our common stock. Of the 120,737,337 shares currently outstanding, 59,992,555 shares are freely tradable without restriction.

 

The Financial Industry Regulatory Authority, or FINRA, has adopted sales practice requirements which may also limit a stockholder's ability to buy and sell our stock.

 

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

 

The value of our common stock may be affected by matters not related to our operating performance.

 

The value of our common stock may be affected by matters not related to our operating performance for reasons that may include the following:

 

  U.S. and worldwide supplies and prices of and demand for oil and natural gas;
     
  political conditions and developments in the United States;
     
  political conditions in oil and natural gas producing regions;
     
  investor perception of the oil and gas industry;
     
  limited trading volume of our common stock;
     
  change in environmental and other governmental regulations;
     
  the prices of oil and natural gas;
     
  announcements relating to our business or the business of our competitors;
     
  our liquidity; and
     
  our ability to raise additional funds.

 

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These and other factors are largely beyond our control, and the impact of these risks, singly or in the aggregate, may result in material adverse changes to the market price of our common stock and our results of operations and financial condition.

 

ITEM 1B.UNRESOLVED STAFF COMMENTS

 

None.

 

ITEM 2.PROPERTIES

 

Our offices are located at 175 South Main Street, Suite 900, Salt Lake City, Utah 84111. For a full description of the properties associated with our operating activities, see “Item 1. Business—Properties” and “Item 1. Business—Projects.”

 

ITEM 3.LEGAL PROCEEDINGS

 

On September 30, 2013 Roger Buller filed an action against Richfield Oil & Gas Company in the Twentieth Judicial District Court of Russell County, Kansas. The case was filed based on a claimed failure to pay a Note in full. Richfield contends that the Note has been paid in full by the issuance of Richfield Common Stock which was accepted by Mr. Buller for the payment of the Note. The action requests the sum of $10,193 plus interest. On December 17, 2014 a Trial was conducted in the Twentieth Judicial District Court of Russell County, Kansas. The Court ruled in favor of Richfield Oil & Gas Company. Richfield was awarded its attorney fees in this action.

 

In October 2013 Stratex filed an action against Timothy Kelly seeking damages against him for breach of fiduciary duty and usurpation of corporate opportunities in the Westchester County Superior Court Index No 67528/2013. On September 18, 2014, the Westchester County Superior Court of the State of New York (the “Court”) (i) awarded Stratex a judgment against Timothy Kelly (“Kelly”) in the amount of $3,164,000 (plus interest at the rate of 9% per annum) and (ii) dismissed “with prejudice”, all counterclaims previously asserted by Kelly against Stratex. Stratex intends to vigorously pursue the enforcement of the $3,164,000 judgment awarded to Stratex against Kelly.

 

In or about September 2014 Stratex filed an action against Eagleford Energy, Zavala Inc. in the 293rd District Court of Zavala County, Texas. Styled Stratex Oil & Gas Holdings, Inc. v Eagleford Energy, Zavala Inc. Case No 14-09-132090-ZCV The action was for foreclosure of the payment of obligations owed by Eagleford Energy, Zavala Inc. for lease obligations. Prior to foreclosure Eagleford paid the obligations which were owed. On March 31, 2015 this matter was settled by Stratex releasing its interest in the project for the development of the 2926 acres in Zavala County, Texas, to its two partners Eagleford Energy, Zavala Inc and Quadrant Energy, Inc. The parties entered into a mutual release of all obligations.

 

Litigation in the Ordinary Course

 

We have become involved in litigation from time to time relating to claims arising in the ordinary course of our business. We do not believe that the ultimate resolution of such claims would have a material effect on our business, results of operations, financial condition or cash flows. However, the results of these matters cannot be predicted with certainty, and an unfavorable resolution of one or more of these matters could have a material effect on our business, results of operations, financial condition and cash flows.

 

ITEM 4.MINE SAFETY DISCLOSURES

 

Not applicable.

 

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PART II

 

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

 

Market Information

 

Our common stock has been quoted for trading on the OTCBB under the trading symbol “STTX” since April 2012.

 

Although our common stock is currently quoted on the OTCBB, there is no broadly followed or established public trading market for our common stock and there is no assurance that an established public trading market will develop or be maintained. The OTCBB is a significantly more limited market than the national securities exchanges. The quotation of our common stock on the OTCBB may result in a less liquid market available for our shareholders to trade common stock, could depress the trading price of common stock and could have a long-term adverse impact on our ability to raise capital in the future.

 

As of March 31, 2015, (i) 120,737,337 shares of our common stock were outstanding, (ii) warrants to purchase 32,426,907 shares of our common stock were outstanding, (iii) Options to purchase 15,350,000 shares of our common stock were outstanding, (iv) notes convertible into 73,645,128 shares of our common stock were outstanding, and (v) 0 shares of our preferred stock were outstanding.

 

Trading in the Company’s common stock is limited and the prices below should be viewed as an indication that there is any established public market for the Company’s securities.

 

Quarters Ended  High $   Low $ 
         
First Quarter Ending March 31, 2015  $0.12   $0.04 
           
Fourth Quarter Ending December 31, 2014  $0.30   $0.05 
Third Quarter Ending September 30, 2014  $0.37   $0.20 
Second Quarter Ending June 30, 2014  $0.61   $0.19 
First Quarter Ending March 31, 2014  $0.35   $0.15 
           
Fourth Quarter Ending December 31, 2013  $0.22   $0.07 
Third Quarter Ending September 30, 2013  $1.11   $0.12 
Second Quarter Ending June 30, 2013  $1.73   $0.89 
First Quarter Ending March 31, 2013  $1.05   $0.93 

 

As of March 31, 2015, the closing sales price for our common stock on the OTCBB was $0.10.

 

Dividends

 

We have not paid dividends on our common stock and do not expect to declare and pay dividends on our common stock in the foreseeable future.

 

Securities Authorized for Issuance under Equity Compensation Plans

 

The following is certain information about our equity compensation plans as of December 31, 2014.

 

Plan Category  Number of securities to be issued upon exercise of outstanding options, warrants and rights   Weighted–average exercise price of outstanding options, warrants and rights   Number of securities remaining available for future issuance under equity compensation plans (1) 
Equity Compensation Plans approved by security holders   6,100,000   $0.17    5,900,000 

 

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In 2012, we adopted a new Stock Incentive Plan (the “2012 Plan”), under which we approved and reserved 12,000,000 shares of common stock to be issued as stock options to our employees, officers, directors. The Options described in this Item 5 do not take into account or include 33,450,677 warrants to purchase common stock that were issued by the Company as of December 31, 2014.

 

Recent Sales of Unregistered Securities

 

The following summarizes all sales of our unregistered securities during the three months ended December 31, 2014. The securities listed in each of the below referenced transactions were (i) issued without registration and (ii) were issued in reliance on the private offering exemptions contained in Sections 4(a)(2), 4(a)(5) and/or 3(b) of the Securities Act and on Regulation D promulgated thereunder, and in reliance on similar exemptions under applicable state laws as a transaction not involving a public offering. No placement or underwriting fees were paid in connection with these transactions. Proceeds from the sales of these securities were used for general working capital purposes. The securities are deemed restricted securities for purposes of the Securities Act.

 

During the year ended December 31, 2014, the Company issued the following common stock:

 

Transaction Type  Quantity of Shares   Valuation   Range of Value per Share 
Common stock issued to settle liabilities   270,000   $102,600   $0.38 
Common stock issued for preferred stock   7,000,000    --    -- 
Common stock issued for services   1,625,180    531,854    0.36 
Common stock issued with promissory notes   850,000    170,000    0.20 
Common stock issued in connection with merger   60,616,448    8,183,220    0.14 
Total   70,361,628   $8,987,674   $0.14-0.38 

 

During the year ended December 31, 2014, the Company granted common stock to a consultant for future services. The Company recognizes the fair value of the shares in the statement of operations in the period earned. As of December 31, 2014, the Company has $43,146 in stock compensation related to common stock issuance that is yet to be earned.

 

Preferred Stock Issued During the twelve Months Ended December 31, 2014

 

Pursuant to the Company’s Agreement and Plan of Merger with Richfield Oil & Gas Company (“Richfield”), dated as of May 6, 2014 (the “Merger Agreement”), the exchange of all outstanding shares of our Series A Preferred Stock for 7,000,000 shares of our common stock is a condition to the Company’s and Richfield’s obligation to effect the merger. Each share of our Series A Preferred Stock entitles the holder thereof to cast 1,000,000 votes on all matters submitted to a vote of the stockholders. Accordingly, on August 20, 2014, our board of directors (the “Board”) approved the issuance of 7,000,000 shares of our common stock to Rotary Partners LLC, an entity in which Stephen Funk, our Chief Executive Officer, owns and controls one hundred percent (100%) of the membership interests. Such shares were issued in exchange for the surrender by Rotary Partners of 60 shares (constituting all) of the Company’s outstanding Series A Preferred Stock. Previously, such shares of Series A Preferred Stock had been issued to Mr. Funk who transferred them to Rotary Partners on August 19, 2014.

 

During the year ended December 31, 2013, the Company issued 10 shares of preferred stock held in Treasury.

 

Transaction Type  Quantity of Shares   Valuation   Range of Value per Share 
Services rendered – officers   10   $830   $83.00 
Total   10   $830   $83.00 

 

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Treasury Stock Activity During the twelve Months Ended December 31, 2014

 

During the twelve months ended December 31, 2014, 150,000 shares of common stock was returned to the Company and retired. The stock was originally issued in November 2013 as partial consideration for working and net revenue interests in oil and gas property located in Callahan County, Texas.

 

Warrants Issued During the twelve Months Ended December 31, 2014

 

During the year ended December 31, 2014 the Company re-priced warrants to purchase an aggregate of 875,000 common shares in the capital of the Company from an exercise price of $0.85 to an exercise price of $0.15. All other warrant terms remain the same including the expiry date. (March through May 2018).

 

The Company recorded interest expense related to the re-priced warrants of $14,755 during the year ended December 31, 2014 calculated as the fair value of the re-priced warrants minus the current fair value of the surrendered warrants.

 

During the year ended December 31, 2014 the Company re-priced warrants to purchase an aggregate of 125,000 common shares in the capital of the Company from an exercise price of $0.85 to an exercise price of $0.30. All other warrant terms remain the same including the expiry date. (July 2018).

 

The Company recorded interest expense related to the re-priced warrants of $3,452 during the year ended December 31, 2014 calculated as the fair value of the re-priced warrants minus the current fair value of the surrendered warrants

 

On December 1, 2014 the Company issued 7,011,561 new warrants to former Richfield warrant holders as per the merger agreement. The exercise price and expiration dates remained the same as the previous Richfield warrants. These new warrants were valued at their fair value using the Black-Scholes warrants valuation model and Stratex’s historical data. The calculated fair value of the warrants Stratex issued on closing was $422,067 or $0.06 per warrant

 

Options Issued During the twelve Months Ended December 31, 2014

 

During the year ended December 31, 2014, the Company's board of directors authorized the grant of 5,250,000 stock options, having a total fair value of approximately $1,170,503, with vesting periods ranging from immediate to 2.00 years. These options expire between April 2019 and September 2019.

 

Common Stock Issued During the twelve Months Ended December 31, 2013

 

The Company issued 70,000 shares of common stock to consultants at a price of $0.25 per share as compensation for services.

 

Warrants Issued During the twelve Months Ended December 31, 2013

 

During year ended December 31, 2013 the Company re-priced warrants to purchase an aggregate of 1,400,000 common shares in the capital of the Company from an exercise price of $1.65 to an exercise price of $0.30. All other warrant terms remain the same including the expiry date of October 31, 2017.

 

The Company recorded compensation expense related to the re-priced warrants of $27,427 during 2013 calculated as the fair value of the re-priced warrants minus the current fair value of the surrendered warrants.

 

Holders

 

As of December 31, 2014, we had 768 holders of record of our common stock and no preferred stock holders.

 

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ITEM 6.SELECTED FINANCIAL DATA

 

As a smaller reporting company, we have elected not to provide the disclosure required by this item.

 

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

 

The following discussion and analysis of our financial condition and results of operations should be read together with our financial statements appearing in this annual report. This discussion contains forward-looking statements that involve risks and uncertainties because they are based on current expectations and relate to future events and future financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many important factors, including those set forth in our “Risk Factors.”

 

Overview

 

We are an independent energy company focused on the acquisition and subsequent exploitation and development of predominantly crude oil in Kansas and Texas as well as varied non-operated working interests in North Dakota, Montana, Colorado, Utah and Kansas. In Texas, we have interests in certain properties located in Zavala Counties. Our Zavala County acreage lies within the established oil rim of the very prolific Eagle Ford Shale play, one of the most actively drilled basins in the United States. The play is also known for multiple stacked pay zones and is also highly prospective for the San Miguel, Austin Chalk and Buda formations, which all produce within the general vicinity. Management views our Zavala County acreage as the cornerstone of its present development program. Our Kansas property is situated on acreage where we intend to drill low risk, wells in the Wilcox and Arbuckle formations located in central Kansas area. In Montana, we focus on stacked Williston Basin production primarily from the Bakken Shale, and Three Forks formations. Our Utah property is located in the Central Utah overthrust and the shale play. We are currently participating in the shale play with Whiting Petroleum as the operator.

 

Present corporate strategy is to internally identify those prospects, which may take the form of acquisition of bolt on acreage and/or production within existing core areas or other potentially opportunistic areas of interest. We intend to evaluate those prospects utilizing subsurface geology, geophysical data and existing well control. Currently, we utilize the services of geologists, petroleum engineers and geophysicists with local expertise on a contract basis, in order to maintain a low cost structure.

 

To date, the Company has only held small, passive, non-operated working interests in North Dakota, Montana and Kansas. By virtue of our recent Richfield Merger with Richfield the Company now intends to actively exploit Kansas and Utah properties together with the Zavala County Texas properties. The Company has assumed operator status. Upon assuming the role of operator, subject to the terms of the underlying leases, the Company will be able to have greater control over the timing of expenditures, drilling and completion costs, and operating budgets.

 

The Company currently owns, as of March 31, 2015, an interest in 86 wells, 55 of which account for the Company’s present net production and cash flow. Currently, we hold approximately 35,317 net leasehold acres in Sheridan, Montana, Williams, Billings, Divide, Mountrail, and Stark Counties, North Dakota, Weld County, Colorado, Central Kansas, Central Utah and Zavala County, Texas.

 

The Bakken formation is recognized internationally as a major source of oil reserves. The United States Geological Survey (USGS) estimates that the Bakken has some 4.3 billion barrels of recoverable oil. The Keystone pipeline, which runs along the US-Canada border, was halted by President Obama and we expect it to be approved and construction to be resumed in the near future. If approved, it will be a principal means of transporting the Bakken oil from the Canadian and US portions of the formation to the refineries. It is believed that the Bakken oil fields and the shale gas fields in other parts of the US will make the US energy independent this decade.

 

We expect to continue to acquire oil and gas properties and to build our asset base. As we continue to review business opportunities, we believe that we will need to raise additional capital through equity sales and debt financing to continue to acquire more properties, and business opportunities, such properties are expected to generate cash flow from participation in the development of the drilling programs that each property is designed to support.

 

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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 condition 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 may 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 2013 measured against 2014. The following table sets forth the average New York Mercantile Exchange (NYMEX) oil and natural gas prices for the years ended December 31, 2014 and 2013, as well as the high and low NYMEX price for the same periods:

 

   Years Ended
December 31,
 
   2013   2014 
Average NYMEX prices:        
Oil (Bbl)  $97.97   $91.48 
Natural gas (MMBtu)  $3.652   $4.35 
High / Low NYMEX prices:          
Oil(Bbl):          
High  $105.22   $107.52 
Low  $85.20   $53.45 
Natural Gas (MMBtu):          
High  $4.89   $8.15 
Low  $3.50   $2.74 

 

Results of Operations for the year ended December 31, 2013, as compared to the year ended December 31, 2014:

 

Revenues:

 

We generated revenues of $1,094,466 for the year ended December 31, 2014, and $847,257 for the year ended December 31, 2013. The increase in revenue reflects an increase in sales volumes as a result of the one of the Company’s major wells being returned to production after having been down for several months during the year ended December 31, 2013. Revenues also increased as a result of the Richfield Merger on December 1, 2014.

 

Operating Expenses:

 

  Production expense was $806,190 for the year ended December 31, 2014, and $268,083 for the year ended December 31, 2013. The increase in expenses reflects an increase in the number of producing wells during the year ended December 31, 2014. Production expenses increased to 74% of revenue for the year ended December 31, 2014, compared to 32% of revenue for the year ended December 31, 2013, due to the substantial decline in oil prices during the last half of 2014.
     
  General and administrative expense was $6,242,695 for the year ended December 31, 2014, and $4,406,937 for the year ended December 31, 2013. The increase in expense is primarily attributable to an increase in professional fees from the prior year related to the Richfield Merger, and an increase in stock based compensation to consultants, the majority of which was related to the financing commitment for the Richfield Merger.  In addition, the Company engaged key consultants to assist in the oil and gas efforts.

 

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  Depletion, depreciation and amortization expense was $210,861 for the year ended December 31, 2014, and $150,101 for the year ended December 31, 2013. The increase in expense reflects an increase in total oil production, which was partially offset by a decrease in the per barrel depletion rates reflected in the Company’s reserve reports as compared to the year ended December 31, 2013.
     
  Impairment of oil and gas assets was $3,697,924 for the year ended December 31, 2014, and $0 for the year ended December 31, 2013. Based on the reserve report obtained from the Company’s Third Party Engineers and a review of the well economics, the Company impaired oil and gas assets. During the years ended December 31, 2014, and 2013, the Company recorded abandonment costs of $1,042,975 and $753,865, respectively.

 

Other Income (Expense)-net:

 

Other Income (Expense)-net: Other income (expenses) consists primarily of gains and losses on the change in fair value of derivative liabilities, gains and losses on sales of oil and gas properties and interest expense, all primarily related to the Company’s convertible promissory notes, traditional notes and warrant issuances.

 

Other income (expenses) - net decreased by $(2,558,111) to $(3,071,297) for the year ended December 31, 2014, as compared to other income (expenses) - net of $(513,186) for the year ended December 31, 2013. For the year ended December 31, 2014, other income (expenses) consisted of interest income of $80,951, interest expense of ($4,454,057) a loss on change in fair value of derivative liabilities of ($52,154), a gain on sale of oil and gas properties of $450,000, a gain on settlement of liabilities of $108,600 and other income net of $795,363. For the year ended December 31, 2013, other income (expenses) consisted of interest income of $25, $(1,318,051) in interest expense, a gain on change in fair value of derivative liabilities of $516,880, a gain on sale of oil and gas properties of $275,000, and other income, net of $12,960.

 

Liquidity and Capital Resources:

 

We have incurred net operating losses and operating cash flow deficits since inception, continuing through the first quarter of 2015. 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 December 31, 2014, we had cash and cash equivalents totaling $1,937,225

 

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.

 

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Our financial statements for the year ended December 31, 2014 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 $5,562,247 for the year ended December 31, 2014, as compared to cash used in operating activities of $66,051 during the year ended December 31, 2013. The increase in cash used in operating activities during the year ended December 31, 2014 as compared to the year ended December 31, 2013 is primarily due to an increase in overall net loss for the year from $5,244,915 at December 2013 compared to $13,988,215 at December 31, 2014. This was partially offset by an increase in asset impairment, accretion of debt discount and amortization of debt issuance costs. In addition, during the year ended December 31, 2014 as compared to the year ended December 31, 2013 there was an increase in legal and professional fees, salary and benefit costs and merger related expenses.

 

Cash from Investing Activities

 

Cash used in investing activities for the year ended December 31, 2014 was $9,426,741 as compared to $351,241 during the year ended December 31, 2013. The net increase is due to the Company’s increased purchases of oil & gas properties of $5,370,658 for the year ended December 31, 2014 as compared to $1,163,927 for the year ended December 31, 2014. The Company also provided funds of $4,469,872 to Richfield oil & Gas as part of a credit facility related to the merger of the Companies.

 

Cash from Financing Activities

 

Total net cash provided by financing activities was $16,281,152 for the year ended December 31, 2014, from various debt and equity offerings. Total net cash provided by financing activities during the period ended December 31, 2013 was $951,250 from various debt and equity offerings. For more details about these debt and equity financings, see Notes to the Consolidated Financial Statements for the years ended December 31, 2014 and 2014, included by reference herein.

 

Planned Capital Expenditures

 

Dependent on our ability to obtain sufficient financing, development plans for 2015 include identifying, acquiring and operating properties as well continued development of our existing leases. We will also to continue to participating in the ongoing Authorization for Expense (AFE) process for the existing properties.

 

The Company incurred approximately $3,583,931 in development costs related to the purchase of working interest in wells during the calendar year 2014. Unrelated to any potential acquisitions the Company expects to incur maintenance and operating costs of approximately $60,000 to $85,000 per month for the next twelve months to maintain these assets.

 

Effects of Inflation and Pricing

 

The oil and gas industry is cyclical and the demand for goods and services by oil field companies, suppliers and others associated with the industry put significant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase all other associated costs increase as well. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to the declining prices. Material changes in prices also impact our current revenue stream, estimates of future reserves, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

 

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Critical Accounting Policies

 

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our consolidated financial statements in accordance with United States generally accepted accounting principles (“GAAP”), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.

 

Asset Retirement Obligations

 

The Company follows the provisions of the FASB 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. 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.

 

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 follows 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 consolidated 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.

 

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The tax effects from an uncertain tax position can be recognized in the consolidated financial statements only if the position is more likely than not of being sustained if the position were to be challenged by a taxing authority. We have examined the tax positions taken in our tax returns and determined that there are no uncertain tax positions. As a result, we have recorded no uncertain tax liabilities in our consolidated balance sheet.

 

Oil and Gas Properties, Successful Efforts Method

 

The Company accounts for oil and gas properties by the successful efforts method. Under this method of accounting, 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 FASB 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. 

 

The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and natural gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain the Company’s wells and related equipment and facilities.

   

Depletion of producing oil and gas properties is recorded based on units of production. Acquisition costs of proved properties are depleted on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are depleted on the basis of proved developed reserves. As more fully described below, proved reserves are estimated by the Company’s independent petroleum engineer and are subject to future revisions based on availability of additional information.  Asset retirement costs are recognized when the asset is placed in service, and are depleted over proved reserves using the units of production method. 

 

Oil and gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. The Company compares net capitalized costs of proved oil and gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect the Company’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows based on management’s expectations of future oil and natural gas prices.

 

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. We perform periodic assessment of individually significant unproved crude oil and gas properties for impairment on a quarterly basis and we would recognize a loss at the time if there was an impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploratory activity on adjacent leaseholds, our management and geologists’ evaluation of the lease, and the remaining months in the lease term.

  

The sale of a partial interest in a proved oil and gas property is accounted for as normal retirement and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production depletion rate. If the units-of-production rate is significantly affected, then the sale shall be accounted for as the sale of an asset, and a gain or loss shall be recognized. The unamortized cost of the property or group of properties shall be apportioned to the interest sold and the interest retained on the basis of the fair values of those interests. A gain or loss is recognized for all other sales of producing properties and is included in the results of operations. The sale of a partial interest in an unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to recovery of the cost applicable to the interest retained. A gain on the sale is recognized to the extent the sales price exceeds the carrying amount of the unproved property. A gain or loss is recognized for all other sales of nonproducing properties and is included in the results of operations. 

 

Proved Reserves

 

Estimates of the Company’s proved reserves included in this report are prepared in accordance with U.S. 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.

 

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Use of Estimates

 

The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Such estimates and assumptions impact, among others, the following: allowance for bad debt, 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 consolidated 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.

 

Jumpstart Our Business Startups Act (“JOBS Act”), adopted January 3, 2012

 

We qualify as an “emerging growth company,” as defined in Section 2(a) of the Securities Act as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As such, we are permitted to rely on exemptions from various reporting requirements including, but not limited to, the requirement to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes–Oxley Act of 2002, and the requirement to submit certain executive compensation matters to shareholder advisory votes such as “say on pay” and “say on frequency.”

 

In addition, Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to take advantage of the benefits of this extended transition period. Our financial statements may therefore not be comparable to those of companies that comply with such new or revised accounting standards.

 

We will remain an emerging growth company up to the fifth anniversary of our first registered sale of common equity securities, or until the earliest of (a) the last day of the first fiscal year in which our annual gross revenues exceed $1 billion, (b) the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Exchange Act, which would occur if the market value of our common stock held by non-affiliates exceeds $700 million as of the last business day of our most recently completed second fiscal quarter, or (c) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period.

 

New Accounting Pronouncements

 

From time to time, new accounting pronouncements are issued by FASB that we adopt as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on our financial statements upon adoption.

 

Off-Balance Sheet Arrangements

 

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

 

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ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

As a smaller reporting company, we have elected not to provide the disclosure required by this item.

 

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Our consolidated financial statements required by this item are set forth immediately following the signature page to this annual report on Form 10-K beginning on page F-1 and are incorporated herein by reference.

 

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

 

None.

 

ITEM 9A.CONTROLS AND PROCEDURES

 

Evaluation of Disclosure Controls and Procedures

 

Our management, with the participation of our Chief Executive Officer (“CEO”) and Chief Administrative Officer (“CAO”), has not evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2014. Based on this evaluation, the CEO and CAO have concluded that, as of December 31, 2014, our disclosure controls and procedures were not effective, in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

 

Changes in Internal Control Over Financial Reporting

 

There were no changes made in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended December 31, 2014, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

Management’s Report on Internal Control Over Financial Reporting

 

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control framework and processes are designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation of our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America.

 

Our internal control over financial reporting includes those policies and procedures that:

 

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
   
provide reasonable assurance that transactions are recorded properly to allow for the preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures are being made only in accordance with authorizations of our management and Board of Directors;
   
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements; and
   
provide reasonable assurance as to the detection of fraud.

 

It should be noted that any system of controls, however well designed and operated, can provide only reasonable and not absolute assurance that the objectives of the system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their stated goals under all potential future conditions.

 

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Our management, under the supervision and with the participation of our CEO and CAO conducted an evaluation of our internal control over financial reporting and concluded that, as of December 31, 2014, such internal control over financial reporting is not effective. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Additionally management’s report was not subject to attestation by our registered public accounting firm pursuant to the rules of the SEC that permit us to provide only management’s report in this annual report.

 

ITEM 9B.OTHER INFORMATION

 

None.

 

PART III

 

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

Our articles of incorporation and bylaws provide that our business is to be managed by or under the direction of our Board of Directors. Our bylaws provide that up to seven Directors are elected at our annual meeting to serve until our next annual meeting of stockholders or until their earlier resignation or removal. There are currently one vacancy on our Board of Directors. Pursuant to our bylaws, the Board of Directors may fill this vacancy or, alternatively, may reduce the size of the Board of Directors to eliminate the vacancy. As of the date of this filing, the Board of Directors has not taken any action with respect to the vacancy. Our officers serve at the pleasure of our Board of Directors. There are no family relationships among any of our directors, executive officers, or key employees. The information presented below for each director includes the specific experience, qualifications, attributes and skills that led us to the conclusion that such director should serve on our Board of Directors in light of our business and structure.

 

The following table sets forth the name, age as of March 31, 2015 and position of our directors and executive officers:

 

Name  Age  Position
Alan D. Gaines  59  Executive Chairman
Stephen P. Funk.  52  Chief Executive Officer and Director
Michael J. Thurz  50  Chief administrative Officer and Director
John J. McFadden  70  Director
Joseph P. Tate  71  Director
Frederic L. Saalwachter  70  Director
Michael A. Cederstrom  62  Executive Vice President and General Counsel
James M. Parrish  61  Vice President Operation

 

Alan D. Gaines Mr. Gaines brings approximately 30 years of experience as an energy investment and merchant banker. In 1983, Mr. Gaines co-founded Gaines, Berland Inc., a full service investment bank/advisory and brokerage, specializing in global energy markets, with particular emphasis given small to mid-capitalization public and private companies. Mr. Gaines’ sold his ownership in this entity in 1998. In 2001 Mr. Gaines founded Dune Energy, Inc. (symbol: DUNR), a publicly traded independent E&P company, and served as the chairman of the board from 2001 to 2011. Mr. Gaines also served as chief executive officer of Dune Energy from its inception until April 2007. From April 2005 until August 2008, Mr. Gaines served as vice-chairman and from April 2005 until July 2008, Mr. Gaines served as a director of Baseline Oil & Gas. From 2006 to 2010, Mr. Gaines served as a director of Cross Canyon Energy Corp., where he also served as chief executive officer from April 2006 to September 2007 and as chairman of the board from April 2006 to May 2008. From February 2011 until April 2011, Mr. Gaines served as chairman of the board of Strategic American Oil Corp. (now known as Hydrocarb Energy Corp., symbol: HECC), and from January 2012 until February 2014, Mr. Gaines served on the board of directors of Eagleford Energy Inc. (symbol: EFRDF), both independent E&P companies. Mr. Gaines holds a B.B.A. in Finance from Baruch College and an M.B.A. in Finance (with distinction) from The Zarb School, Hofstra University Graduate School of Management.

 

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Stephen P. Funk Mr. Funk brings over 30 years of experience in finance to Stratex. He has served as the principal of Alta Investments LLC (“Alta”), a company providing specialized investment banking consultant services, since founding it in 1999. Mr. Funk has consulted on numerous mergers, acquisitions and strategic alliances. From 2007 through 2010, Mr. Funk served as the managing member of Cherokee Enterprises LLC, a construction dewatering firm serving the heavy construction industry. From 1999 through 2001, Mr. Funk was a vice president at Windham Associates, a mergers and acquisition firm and from 1991 to 1999, he worked at Merrill Lynch as a vice president in Business Financial Services. Mr. Funk graduated from Marist College in 1984 with a B.S. in Business Administration, Finance.

 

Michael J. Thurz Mr. Thurz Michael J. Thurz is a certified public accountant (CPA) with approximately 14 years of audit experience. Since March 2010, Mr. Thurz has served as a Senior Vice President of Accounting Resources Inc., a company providing back office accounting through CFO level services for companies engaged in a variety of industries including oil & gas. While employed at Accounting Resources, Mr. Thurz assisted Stratex management with day to day accounting activities and the preparation of its periodic reports for which Accounting Resources was paid an aggregate of $147,000 over the past three and one-half years. From October 2007 to February 2010, he served as Audit Senior Manager at Saslow, Lufkin & Buggy, LLP and from February 1993 to June 2007, he served as President of National Supplement Warehouse, a vitamin and supplement retail store chain. Mr. Thurz received his BSBA (accounting) from the University of Hartford in 1987.

 

John J. McFadden has served on Richfield’s Board of Directors since May 18, 2008. Following the Richfield Merger, Mr. McFadden joined the Stratex Board on December 1, 2014. Mr. McFadden brings to our Board of Directors over 40 years of experience in the investment banking industry. Since 1998 Mr. McFadden has been self-employed as a consultant, providing consultation to his clients regarding both investment banking and energy matters. His clients include Equitable Gas, Select Energy and Optimira Energy. From 1996 until 1998, Mr. McFadden was employed as the Senior Managing Director of Cambridge Holding and Cambridge Partners, LLC, a private investment company based in New York, NY. From 1968 until 1996 Mr. McFadden was employed by The First Boston Corporation (later Credit Suisse First Boston) with a variety of responsibilities in corporate finance and public finance, including service as Vice President and Treasurer. Mr. McFadden has previously served as a director of two publicly-traded companies, of Advanced Battery Technologies, Inc. and China Digital Animation, Inc. Mr. McFadden received a Bachelor of Arts degree from St. Bonaventure University.

 

Joseph P. Tate has served on Richfield’s Board of Directors since March 31, 2012. Following the Richfield Merger, Mr. Tate joined the Stratex Board on December 1, 2014. Mr. Tate brings more than 40 years of entrepreneurial experience to our company. In 1967, he founded Valley Sanitation, a two-truck waste hauling business in Fort Atkinson, Wisconsin. The company had three employees and annual revenues of $40,000 the first year. In 1993, he merged his 12-location business with 10 others to form Superior Services, Inc., a solid waste, special waste and hazardous waste business serving the Midwest (“Superior”). By 1999, Superior had a successful initial public offering, a secondary offering and finally, sold to Vivendi, a French conglomerate. At the time of the sale, Superior had over 3,000 employees. Mr. Tate served as President/CEO and Chairman of the Board at Superior. After the sale of Superior, Mr. Tate started Tate Enterprises, a company that offers professional management services to the organizations in which he is a substantial equity partner. Mr. Tate is an officer, director and/or significant equity holder in several companies including: OnMilwaukee.com, an internet city guide, TMX, a decorative mulch company, Tate Farm, a ranch in Utah, Mason Car Wash, a car wash and oil change business, Sherman Disposal, a solid waste disposal company, Coastal Disposal, a solid waste disposal company, Midwest Compost, a grass and leaves transfer station and Rapport Leadership, an organizational and leadership development company. Mr. Tate recently retired from the non-profit boards of Second Harvest of Wisconsin and the Next Door Foundation. He currently serves as a director of CEO Leadership Academy, The Tate Family Foundation and Rapport Leadership.

 

Frederic L. Saalwachter has decades of experience in the energy industry with capital markets financing transactions and advisory services provided to a wide variety of oil & gas and other energy companies. As an investment banker, Mr. Saalwachter has arranged numerous debt and equity financings and provided strategic advice in connection with a large number of mergers and acquisitions. Presently, Mr. Saalwachter serves as a Managing Director in Capital Markets at StormHarbour Securities, LP, a position he has held since March 2014. He was previously Managing Director and Head of the Energy Investment Banking Group at the PrinceRidge Group and for most of the prior 16 years, he served as Managing Director in Energy Banking for the Sanders Morris Group and affiliated companies. Previously, he was a senior banker for Shearson Lehman, Kemper Securities and Warburg Paribas Becker. Mr. Saalwachter was a co-founder of a group of oilfield service companies with businesses primarily dedicated to offshore drilling. Mr. Saalwachter holds a B.A. degree from Fairfield University.

 

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Michael A. Cederstrom served as Richfield’s General Counsel and Corporate Secretary from December 15, 2011 until September 9, 2014. On September 9, 2014 Mr. Cederstrom was appointed the President and CEO of Richfield and served in this capacity until December 1, 2014. On February 13, 2015 Mr. Cederstrom was appointed Executive Vice President and General Counsel of Stratex. Mr. Cederstrom provided legal services to Richfield as an independent contractor from March 2011 until December 15, 2011. Mr. Cederstrom served as General Counsel to Hewitt Petroleum, Inc. from May 2009 until March 2011. Mr. Cederstrom has over 32 years of experience as a corporate attorney representing businesses in various capacities, including SEC reporting and compliance. Mr. Cederstrom has represented oil and gas exploration and production companies for over 18 years in all areas including leasing, environmental and regulatory compliance and securities matters. Mr. Cederstrom practiced law with Dexter & Dexter Attorneys at Law from 2004 to 2008. Mr. Cederstrom’s law practice specialized in business law, including initial organization of business entities, maintenance of the entity, employment matters and business tax matters. In 1997 Mr. Cederstrom organized and registered the shares of HEGCO Canada, Inc. on the CDNX, and served as its General Counsel and CFO from 1997 to 2002. Mr. Cederstrom has participated in the organization of a bank and registration of the bank's shares on the New York Stock Exchange, and has served on the Board of Directors of two banks and several other businesses. Mr. Cederstrom received a Bachelor of Science degree in Finance from the University of Utah and a Juris Doctorate degree from Southwestern University. While at Southwestern University, Mr. Cederstrom earned two Jurisprudence Awards for exceptional achievement in the study of Tax and Estate Planning.

 

James M. Parrish Mr. Parrish brings nearly 40 years of upstream and midstream oil and gas experience to Stratex. Prior to joining Stratex in September 2014, Mr. Parrish provided consulting services to a number of oil and gas companies focused on the acquisition of assets primarily in Texas. From 2007 thru 2010, Mr. Parrish served as president and chief executive officer of Infiniti Energy, LLC, a privately held E&P company based in Dallas, Texas. In 2004, Mr. Parrish co-founded Hurricane Energy, LLC, a privately held E&P company that was subsequently merged into Maverick Oil & Gas Corp. (symbol: MVOG) in March 2005, where Mr. Parrish served as executive vice president until late 2006. Mr. Parrish attended North Texas State University from 1972-1974.

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

Section 16(a) of the Exchange Act requires our directors and executive officers, among others, to file with the SEC an initial report of ownership of our common shares on Form 3 and reports of changes in ownership on Form 4 or Form 5. Persons subject to Section 16 are required by SEC regulations to furnish us with copies of all Section 16 forms that they file related to transactions in our stock. Under SEC rules, certain forms of indirect ownership and ownership of our common stock by certain family members are covered by these reporting requirements. As a matter of practice, our administrative staff assists our directors and executive officers in preparing initial ownership reports and reporting ownership changes and typically files these reports on their behalf.

  

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ITEM 11.EXECUTIVE COMPENSATION

 

Summary Compensation Table

 

The table below sets forth compensation earned by our named executive officers in 2014 and 2013 for services rendered in all capacities to us and our subsidiaries.

 

Name and Principal Position  Year   Salary   Bonus   Stock Awards   Option Awards   All Other Compensation   Total 
       ($)   ($)   ($)   ($)   ($)   ($) 
       (1)       (2)   (3)   (4)     
Alan D. Gaines   2014    233,333    -    -    503,826    -    737,159 
Executive Chairman of the Board   2013    -    -    -    -    -    - 
                                    
Stephen P Funk.   2014    302,500    -    -    228,168    -    530,668 
President and Chief Executive Officer and Director   2013    250,000    -    10    501,517    9,000    760,527 
                                    
Michael Thurz   2014    58,333    -    -    166,103    -    224,436 
Chief Administrative Officer and Director   2013    -    -    -    -    -    - 
                                    
Matthew Cohen   2014    76,667    -    -    259,294    -    335,961 
Executive vice President and General Counsel   2013    -    -    -    -    -    - 
                                    
James Parrish   2014    47,100    -    -    57,195    -    104,295 
Director of Operations   2013    -    -    -    -    -    - 
                                    
Michael  A Cederstrom   2014    27,917    -    -    -    -    27,917 
Vice President Corporate Affairs   2013    -    -    -    -    -    - 

 

(1)

 

In 2014, base salary compensation was earned by and paid to our named executive officers as follows: (i) Mr. Gaines was appointed Executive Chairman of the Board on May 6, 2014. Mr. Gaines’ annual salary is $350,000 and he earned $233,333 in 2014, all of which has been paid as of December 31, 2014.

 

(ii) Mr. Funk has annual salary $302,500, all of which has been paid as of December 31, 2014. Mr. Funk was also paid $76,500 in accrued wages during 2014.

(iii) Mr. Thurz earned $58,333, all of which has been paid as of December 31, 2014.

(iv) Mr. Cohen earned $76,667, all of which has been paid as of December 31, 2014.

(v) Mr. Parrish earned $47,100, all of which has been paid as of December 31, 2014.

(vi) Mr. Cederstrom earned $27,917, all of which has been paid as of December 31, 2014.

 

In 2013, base salary compensation was earned by and paid to our named executive officers as follows: (i) Mr. Mr. Funk earned $250,000, of which $173,500 was paid in cash in 2013 and the remaining amount was accrued at December 31, 2013.

 

(2) This column reflects amounts awarded pursuant to our incentive plan and other stock awards, each of which were established and approved by the Board of Directors.
   
(3) This column reflects amounts based upon the Black-Scholes valuation model for stock option awards.
   
(4) In 2013, “All Other Compensation” which includes auto expenses and medical reimbursement earned by our named executive officers.

 

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Employment and Consulting Agreements

 

We have entered into written executive employment agreements with each of our named executive officers, The compensation payable to each named executive officer under such officer’s Executive Agreement is set forth in the footnotes to the Summary Compensation Table, above. Other than terms relating to each named executive officer’s compensation, the Executive Agreements contain identical terms and conditions, which are described below. Each of the Executive Agreements provide that year-end cash and/or share bonuses are at the discretion of the Board of Directors, and are based on our achievement of specified predetermined and mutually agreed-upon performance objectives each year.

 

Effective January 1, 2015, the salary of the officers and directors was reduced by 75%.

 

Elements of Compensation

 

The total compensation and benefits program for our executives generally consists of the following components:

 

  base salaries and/or consulting fees;
     
  annual incentive bonuses;
     
  discretionary bonuses;
     
  long-term equity-based incentive compensation;
     
  health and welfare benefits;
     
  perquisites; and
     
  severance payments/change of control.

 

Base Salaries

 

We provide base salaries to compensate our executive officers for services performed during the fiscal year. This provides a level of financial certainty and stability in a historically volatile and cyclical industry. Base salaries are designed to reflect the experience, education, responsibilities and contribution of each individual executive officer.

 

Annual Incentive Bonuses

 

We provide annual stock or cash incentive bonuses to our directors, executive officers, employees and consultants. These bonuses provide variable compensation earned only when performance goals established, from time to time, by our Board of Directors are achieved. Incentive bonuses are designed to reward these individuals for the achievement of certain corporate and executive performance objectives set by our Board of Directors and for contributions to the achievement of certain of our objectives. Any annual incentive bonus paid by Stratex is payable in cash or Stratex stock, at the election of the individual receiving such bonus.

 

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Discretionary Bonuses

 

In addition to annual incentive bonuses discussed above, our Board of Directors may also approve the payment of discretionary bonuses to officers and other employees in recognition of significant achievements.

 

Health and Welfare Benefits

 

We offer health and welfare programs to all eligible employees. Under the terms of their employment agreements, the named executive officers are eligible for the same broad-based benefit programs on the same basis as the rest of our employees. Our health and welfare programs include health, pharmacy and dental benefits.

 

Severance Payments/Change of Control

 

We have employment and/or consulting agreements in place with each of our executive officers providing for lump-sum severance compensation upon termination of the officer’s employment for a variety of reasons, including a change of control.

 

Interlocks and Insider Participation

 

As a smaller reporting company, we have elected not to provide the disclosure required by this item

  

Director Compensation

 

The following table provides information concerning compensation paid to our directors for the most recently completed fiscal year. The fees paid to directors in Stratex common stock are recorded in accordance with applicable accounting standards, and these amounts represent the aggregate fair value of the awards on the date of grant. The ultimate value realized by the director may or may not equal the fair market value on the date of grant. The shares are restricted from sale and although our common stock is currently quoted on the OTCBB, there is no broadly followed and established public trading market for our common stock. We determine the fair value of the shares on the date of grant based on the share price we received in share issuances for cash, settlement of debt or property acquisition at or around the date of grant.

 

Name     Fiscal Year  Fees Earned or Paid In Cash
($)
   Stock
Awards
($)
   Total
($)
 
John J. McFadden  (1)  2014   -    -    - 
Joseph P. Tate  (2)  2014   -    -    - 
Frederic  L. Saalwachter  (3)  2014  $7,500    -   $7,500 
Stephen P. Funk  (4)  2014   -    -    - 
Michael Thurz  (5)  2014   7,500    -    7,500 
Alan D. Gaines  (6)  2014   -    -    - 

 

(1) John J. McFadden has served as one of our non-employee directors since December 2014. In 2014, Mr. McFadden did not earn, nor was he paid any fees for services as a director of Stratex.
   
(2) Joseph P. Tate has served as one of our non-employee directors since December 2014. In 2014, Mr. Tate did not earn, nor was he paid any fees for services as a director of Stratex.
   
(3)

Frederic L. Saalwacher has served as one of our non-employee directors since August 1, 2014. In 2014, Mr. Saalwachter’ earned $7,500 for director’s fees.

   
(4) Stephen P. Funk has served as a Director since April 1, 2012.  In 2014, Mr. Funk did not earn, nor was he paid any additional fees for services as a director.
   
(5) Michael Thurz has served as one of our directors since August 1, 2014. In 2014, Mr. Thurz earned $7,500 for director’s fees.
   
(6) Alan D. Gaines was appointed Executive Chairman of the Board on May 6, 2013.  He is currently serving as Chairman of our Board of Directors. In 2014, Mr. Gaines did not earn, nor was he paid any additional fees for services as a director.

 

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Ongoing Director Compensation in 2014

 

Effective August 20, 2014, our independent directors are compensated with an annual stipend of $30,000 paid in quarterly installments either in cash or common stock at the discretion of the Board of Directors. The independent directors are also eligible participate in the annual incentive program.

 

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

 

The following table sets forth, as of December 31, 2014, certain information regarding beneficial ownership of our common stock by (i) each person or entity who is known by us to own beneficially more than 5% of the outstanding shares of our common stock, (ii) each of our directors, (iii) each of our executive officers, and (iv) all of our current directors and executive officers as a group. As of March 31, 2015, we had one class of voting securities that consisted of 120,737,337 shares of our common stock issued and outstanding. Beneficial ownership is determined in accordance with the rules of the SEC and does not necessarily indicate beneficial ownership for any other purpose. Under these rules, beneficial ownership includes those shares of common stock over which the stockholder had sole or shared voting or investment power. In computing the number and percentage of shares beneficially owned by a person, shares of common stock that a person has a right to acquire within sixty (60) days of December 31, 2014, pursuant to options, warrants or other rights are counted as outstanding, while these shares are not counted as outstanding for computing the percentage ownership of any other person. The following table is based upon information supplied by directors, officers and principal stockholders.

 

Name (1)  Number of
Shares
   Percent of
Common Stock
 
Directors and Officers:        
Alan D. Gaines   13,164,552(2)   5.50%
Stephen P. Funk   13,100,000(3)   5.48%
John J. McFadden   75,324    .03%
Michael A. Cederstrom   2,894,945    1.19%
Joseph P. Tate   1,238,489(4)   .52%
Michael J. Thurz   3,043,900(5)   1.27%
Frederic L. Saalwachter   250,000(6)   .10%
Directors and Officers as a Group (7 persons)   33,645,816    14.10%
 

(1) As used in this table, “beneficial ownership” means the sole or shared power to vote, or to direct the voting of, a security, or the sole or shared investment power with respect to a security (i.e., the power to dispose of, or to direct the disposition of, a security). Unless otherwise indicated, the address of each stockholder is 175 S. Main Street, Suite 900, Salt Lake City, UT. 84111.
   
(2)

Consists of the 4,764,532 shares owned by Alan D. Gaines (ii) 300,000 shares held in the name of Brent Gaines, 300,000 shares held in the name of Derek Gaines, 300,000 shares held in the name of Ilana Gaines and 7,500,000 shares issuable upon exercise of a warrant at $.15 per share issued to Alan Gaines in connection with the execution of his consulting agreement. The address of Mr. Gaines is 100 South Doheny Drive, Penthouse 7 (Apt. 1107), Los Angeles, CA. 90048.

 

(3)

Consists of the 8,000,000 shares owned by Rotary Partners LLC which Mr. Funk has voting and dispositive control of. It also includes 3,600,000 shares of common stock underlying a stock option, exercisable at $0.08 per share and (iii) 1,500,000 shares of common stock underlying a stock option, exercisable at $0.50 per share

 

(4) Consists of the following shares owned by Joseph P. Tate, or of which Mr. Tate may be deemed to be the beneficial owner: (i) 1,180,989 shares held in the name of Joseph P. Tate, (ii) 57,500 shares held in the name of Jennifer Tate, Mr. Tate’s spouse. In addition, Mr. Tate is a holder of 205,000 outstanding warrants exercisable within 3 years from the date of issuance. The address of Mr. Tate and his spouse is 3252 No. Lake Drive, Milwaukee, WI. 53211.
   
(5) Consists of the 43,900 shares owned by Michael J Thurz. It also includes 1,500,000 shares of common stock underlying a stock option, exercisable at $0.30 per share and 1,500,000 shares of common stock underlying a stock warrant, exercisable at $0.15 per share The address of Mr. Thurz is 24 Webster Lane, Rocky Hill CT. 06067.
   
(6) Includes 250,000 shares of common stock underlying a stock option, exercisable at $0.15 per share.

 

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ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

Certain Relationships and Related Transactions

 

We are an oil and gas exploration and production company, with a growth strategy focused on identifying, acquiring, and developing oil and natural gas resources. The majority of our activities to date have involved the identification and acquisition of leases of property in which oil or natural gas are either known to exist, or in which we believe oil and natural gas are likely to be discovered. Our operations have not produced significant cash flows, and we have relied almost exclusively on external sources of liquidity. We have historically met our capital requirements through the issuance of common and preferred stock, short-term borrowings and selling working interests in our oil and natural gas properties. Some of these transactions have involved related parties, including directors and executive officers, existing shareholders, and their affiliates. In addition, we obtained many of our leases in transactions with related parties of Richfield, the Company that we merged with in the Richfield Merger.

 

For the foreseeable future our operations will not be sufficient to provide for our planned capital expenditures and we will continue to require funding from external sources. We intend to seek additional capital through equity financings, debt financings and/or credit facilities.

 

The related-party transactions described below were reviewed and approved by a majority vote of the Board of Directors of Richfield the Company that we merged with in the Richfield Merger and were completed on the same terms as other independent third-party transactions at or around the time of the transaction. With respect to transactions in which the related party is also a member of our Board of Directors, such director abstained from voting to approve the transaction.

 

  A. Joseph P. Tate, a Director

 

Joseph P. Tate became a director of Stratex effective December 1, 2014. Prior to the Richfield Merger, Mr. Tate was a Director of Richfield and entered into the following transactions between January 1, 2012 and November 30, 2014:

 

Mr. Tate is a beneficial owner of land within the HUOP Freedom Trend Prospect. The Company has entered into two oil and natural gas leases with Mr. Tate totaling 1,816 acres (the “Tate Leases”). The Tate Leases consist of i) a new lease the Company entered into in March 2012 relating to 400 acres, for $100,000; and ii) the renewal of an existing lease the Company entered into on March 2012 for a five-year term relating to 1,416 acres, for $283,200. The total amount of $383,200 was paid to Mr. Tate through the issuance of 153,280 shares of common stock, valued at $2.50 per share. Pursuant to the terms of each Tate Lease, Mr. Tate is entitled to 12.50% landowner royalty-interest revenues relating to hydrocarbons produced by Richfield relating to each of the Tate Leases. No oil or natural gas has been extracted from the HUOP Freedom Trend Prospect and therefore the Company has not paid Mr. Tate any landowner royalties with respect to the Tate Leases;
 
64
 
  

Director Independence

 

Our common stock is currently quoted on the OTCBB, which does not impose independence requirements on our Board of Directors or any committee thereof; however, we have elected to adopt the independence standards of the NYSE listing rules. NYSE listing rules require a majority of an issuer’s directors be “independent,” as defined by NYSE listing rules. Generally, a director does not qualify as an independent director under these rules if the director or a member of the director’s immediate family has had in the past three years certain relationships or affiliations with the issuer, the issuer’s external or internal auditors, or other companies that do business with the issuer. We intend to nominate persons considered independent under the objective standards of independence set forth in the NYSE listing rules for election by the shareholders to fill any additional seats on our Board of Directors in the future. Our Board of Directors has determined that John J. McFadden, Joseph P. Tate and Frederic Saalwachter are considered independent based on the NYSE listing rules.

 

ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

Mantyla McReynolds, LLC audited our financial statements for the years ended December 31, 2014, and Mahoney Sabol & Company LLP audited our financial statements for the years ended December 31, 2013.

 

Policy for Approval of Audit and Permitted Non-Audit Services

 

The Board of Directors, in its discretion, may direct the appointment of different public accountants at any time during the year, if the Board believes that a change would be in the best interests of the shareholders. During 2014 and 2013, the Board of Directors considered the audit fees, audit-related fees, tax fees and other fees paid to our accountants, as disclosed below, and determined that the provision of such services by our independent registered public accounting firm was compatible with the maintenance of that firm’s independence in the conduct of its auditing functions.

 

65
 

 

Audit and Related Fees

 

The following table sets forth the aggregate fees billed by Mahoney Sabol & Company, LLP and Mantyla McReynolds for professional services rendered in fiscal years ended December 31, 2014 and fees billed by Mahoney Sabol & Company LLP for professional services rendered in fiscal years ended December 31, 2013.

 

   2014   2013 
Audit Fees (1)  $87,125   $55,500 
Audit-Related Fees (2)  $7,500   $8,315 
Tax Fees (3)  $24,500   $16,120 
Total Fees  $119,375   $79,935 

 

(1) “Audit Fees” represent fees for professional services provided in connection with the audit of our annual financial statements and review of our quarterly financial statements included in our reports on Form 10-Q, and audit services provided in connection with other statutory or regulatory filings.

 

(2) “Audit-Related Fees” generally represent fees for assurance and related services reasonably related to the performance of the audit or review of our financial statements.

 

(3) “Tax Fees” generally represent fees for tax advice and the amount billed for the preparation of our federal and state tax returns.

 

66
 

 

PART IV

 

ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

(a) Consolidated Financial Statements:

 

See “Index to Consolidated Financial Statements” set forth on page F-1.

 

(b)Financial Statement Schedules:

 

All schedules for which provision is made in the applicable accounting requirements of the Securities and Exchange Commission are not required or the required information has been included within the consolidated financial statements or the notes thereto.

 

(c) Exhibits:

 

The list of exhibits in the Exhibit Index to this annual report is included by reference.

 

67
 

 

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

STRATEX OIL & GAS HOLDINGS, INC.

     
Dated:  April 16, 2015 By: /s/ Stephen P. Funk
    Stephen P. Funk
    Chief Executive Officer
     
Dated:  April 16, 2015 By: /s/ Michael Thurz
    Michael Thurz.
    Chief Administrative  Officer

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

/s/ STEPHEN P. FUNK.   President, Chief Executive Officer  

April 16, 2015

Stephen P. Funk   (Principal Executive Officer)    
         
/s/ MICHAEL THURZ   Chief Administrative Officer and Director  

April 16, 2015

Michael Thurz   (Principal Financial Officer)    
         
/s/ ALAN D. GAINES   Executive Chairman  

April 16, 2015

Alan D. Gaines        
         
/s/ JOHN J. MCFADDEN   Director  

April 16, 2015

John J. McFadden        
         
/s/ JOSEPH P. TATE   Director  

April 16, 2015

Joseph P. Tate        
         
/s/ FREDERICK SAALWACHTER   Director  

April 16, 2015

Frederic Saalwachter        

 

68
 

 

 

Stratex Oil & Gas Holdings, Inc.

Consolidated Financial Statements

December 31, 2014

 

Table of Contents

 

  Page(s)
   
Reports of Independent Registered Public Accounting Firms F-2
   
Consolidated Balance Sheets as of December 31, 2014 and 2013 F-4
   
Consolidated Statements of Operations
For the Years Ended December 31, 2014 and 2013
F-5
   

Consolidated Statements of Stockholders’ Equity

For the Period January 1, 2013 through December 31, 2014

F-6
   
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2014 and 2013
F-7
   
Notes to Consolidated Financial Statements F-8

 

F-1
 

 

 

  

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Stockholders and the Board of Directors

 

Stratex Oil & Gas Holdings, Inc.

Salt Lake City, UT

 

We have audited the accompanying consolidated balance sheet of Stratex Oil & Gas Holdings, Inc. (“the Company”) as of December 31, 2014 and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

 

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 has determined that it 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 provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Stratex Oil & Gas Holdings, Inc. as of December 31, 2014 and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, the Company has incurred substantial losses from operations causing negative working capital and negative operating cash flows. These factors raise substantial doubt about its ability to continue as a going concern. Management’s plans in regards to these matters are also described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

/s/ Mantyla McReynolds LLC

 

Salt Lake City, UT

April 16, 2015

 

F-2
 

  

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

   

To the Board of Directors and
Stockholders of

Stratex Oil & Gas Holdings, Inc

 

We have audited the accompanying consolidated balance sheet of Stratex Oil & Gas Holdings, Inc. (the “Company”) as of December 31, 2013, and the related consolidated statements of operations, stockholders’ equity and cash flows for the year ended December 31, 2013. Stratex Oil & Gas Holdings, Inc.’s management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated 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 consolidated 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Stratex Oil & Gas Holdings, Inc. as of December 31, 2013, and the results of its operations and its cash flows for the year ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the financial statements, the Company has suffered losses from operations and has an accumulated deficit, which raises substantial doubt about its ability to continue as a going concern. Management's plans regarding those matters also are described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

/s/ Mahoney Sabol & Company, LLP

 

Glastonbury, Connecticut

March 27, 2014

 

F-3
 

 

Stratex Oil & Gas Holdings, Inc.

Consolidated Balance Sheets

 

   December 31,
2014
   December 31,
2013
 
         
Assets
         
Current Assets:        
Cash  $1,937,225   $609,061 
Accounts receivable   448,702    18,220 
Prepaid expenses   39,593    2,800 
Total Current Assets   2,425,520    630,081 
           
Deposits   128,805    10,025 
Debt issuance costs   1,887,378    - 
Oil and gas property, plant and equipment:          
Proven property - net   9,834,506    755,682 
Unproven property   10,951,429    1,520,870 
Support facilities and related well equipment - net   2,652,271    138,081 
Vehicles, furniture and equipment - net   122,309    2,380 
Total Assets  $28,002,218   $3,057,119 
           
Liabilities and Stockholders' Equity 
           
Current Liabilities:          
Accounts payable and accrued liabilities  $3,609,890   $904,615 
Liability to be issued in stock   -    9,000 
Due to former officer - current   -    715,000 
Demand notes payable   322,575    216,000 
Current maturities of notes payable - net of debt discount   573,094    - 
Current maturities of convertible notes payable - net of debt discount   138,182    - 
Capital lease obligations   88,000    - 
Derivative liability - warrants   128,829    76,675 
Total Current Liabilities   4,860,570    1,921,290 
           
Long-term Liabilities:          
Due to former officer   -    84,000 
Asset retirement obligations   639,349    34,000 
Notes payable - net of debt discount   1,256,477    790,528 
Convertible notes payable, net of debt discount   18,663,203    - 
           
Total Long-Term Liabilities   20,559,029    908,528 
           
Total Liabilities   25,419,599    2,829,818 
           
Commitments and Contingencies          
           
Stockholders' Equity:          
Series A, convertible preferred stock, $0.0001 par value; 400 shares authorized; 100 shares issued; 0 and 60 shares outstanding, respectively   -    1 
Common stock, $0.01 par value; 750,000,000 shares authorized; and 116,904,004 and 46,692,376 shares issued and outstanding, respectively   1,169,038    466,924 
Additional paid in capital   29,321,895    13,680,474 
Accumulated deficit   (27,888,314)   (13,900,098)
Less: Treasury stock, 40 shares Series A, convertible preferred stock, at cost   (20,000)   (20,000)
Total Stockholders' Equity   2,582,619    227,301 
           
Total Liabilities and Stockholders' Equity  $28,002,218   $3,057,119 

 

See accompanying notes to the consolidated financial statements.

 

F-4
 

 

Stratex Oil & Gas Holdings, Inc.

Consolidated Statements of Operations

 

   For The Years Ended 
   December 31,   December 31, 
   2014   2013 
         
Revenue  $1,094,466   $847,257 
           
Operating Expenses:          
Production expenses   806,190    268,083 
Exploration expenses   10,740    - 
Depletion, depreciation and amortization   210,861    150,101 
General and administrative   6,242,695    4,406,937 
Impairment of oil and gas assets   3,697,924    753,865 
Loss on abandonment of oil and gas assets   1,042,975    - 
Total Operating Expenses   12,011,385    5,578,986 
           
Loss From Operations   (10,916,919)   (4,731,729)
           
Other Income and (Expense):          
Interest income   80,951    25 
Interest expense   (4,454,057)   (1,318,051)
Change in fair value - derivative liabilities   (52,154)   516,880 
Gain on sale of oil and gas interests   450,000    275,000 
Gain on settlement of liabilities   108,600    - 
Other income, net   795,363    12,960 
Total Other Income and (Expense)   (3,071,297)   (513,186)
           
Net Loss  $(13,988,216)  $(5,244,915)
           
Net Loss Per Common Share - Basic and Diluted  $(0.25)  $(0.12)
           
Weighted Average Number of Common Shares Outstanding - Basic and Diluted   56,497,169    44,787,051 

  

See accompanying notes to the consolidated financial statements.

 

F-5
 

 

Stratex Oil & Gas Holdings, Inc.

Consolidated Statement of Stockholders' Equity

For the Period from January 1, 2013 to December 31, 2014

 

   Series "A" Preferred Stock   Common Stock   Additional
Paid-In
   Accumulated   Treasury Stock   Stockholders' 
   Shares   Amount   Shares   Amount   Capital   Deficit   Shares   Amount   Equity 
                                     
Balance, January 1, 2013   100   $1    44,281,127   $442,811   $9,769,750   $(8,655,183)   -   $-   $1,557,379 
                                              
Common stock issued for cash ($0.50/share)   -    -    70,000    700    34,300    -    -    -    35,000 
                                              
Conversion of notes payable and interest to common stock   -    -    51,249    512    35,488    -    -    -    36,000 
                                              
Common stock issued for services   -    -    140,000    1,400    33,600    -    -    -    35,000 
                                              
Share based compensation   -    -    -    -    2,344,221    -    -    -    2,344,221 
                                              
Warrants issued with promissory notes   -    -    -    -    1,180,786    -    -    -    1,180,786 
                                              
Purchase of 50 shares of Treasury stock under termination agreement   -    -    -    -    -    -    (50)   (25,000)   (25,000)
                                              
10 preferred shares issued from treasury for services   -    -    -    -    (4,170)   -    10    5,000    830 
                                              
Stock issued with promissory note   -    -    2,000,000    20,000    270,000    -    -    -    290,000 
                                              
Stock issued to acquire oil and gas assets   -    -    150,000    1,501    16,499    -    -    -    18,000 
                                              
Net loss, For the Year ended December 31, 2013   -    -    -    -    -    (5,244,915)   -    -    (5,244,915)
                                              
Balance, December 31, 2013   100   $1    46,692,376   $

466,924

   $13,680,474    $(13,900,098) (40)  $(20,000)  $227,301 
                                              
Common stock issued for services   -    -    1,625,180    16,250    515,604    -    -    -    531,854 
                                              
60 preferred shares converted to 7,000,000 common shares   (60)   (1)   7,000,000    70,000    (69,999)   -    -    -    - 
                                              
Share based compensation   -    -    -    -    1,983,384    -    -    -    1,983,384 
                                              
Warrants issued with convertible promissory notes   -    -    -    -    2,414,643    -    -    -    2,414,643 
                                              
Warrants issued to placement agents   -    -    -    -    903,917    -    -    -    903,917 
                                              
Warrant amendment expense   -    -    -    -    18,207    -    -    -    18,207 
                                              
Stock issued with promissory note   -    -    850,000    8,500    161,500    -    -    -    170,000 
                                              
Beneficial conversion feature   -    -    -    -    1,613,642    -    -    -    1,613,642 
                                              
Stock issued to settle liabilities   -    -    270,000    2,700    99,900    -    -    -    102,600 
                                              
Common stock retired   -    -    (150,000)   (1,500)   1,500    -    -    -    - 
                                              

Stock and Warrants issued to acquire Richfield Oil & Gas, Inc.

   -    -    60,616,448    606,164    7,999,123    -    -    -    8,605,287 
                                              
Net loss, For the Year ended December 31, 2014   -    -    -    -    -    (13,988,216)   -    -    (13,988,216)
                                              
Balance, December 31, 2014   40   $-    116,904,004   $1,169,038   $29,321,895   $(27,888,314)  (40)  $(20,000)  $2,582,619 

 

See accompanying notes to the consolidated financial statements.

 

F-6
 

 

Stratex Oil & Gas Holdings, Inc.

Consolidated Statements of Cash Flows

 

   For The Years Ended 
   December 31,   December 31, 
   2014   2013 
         
Cash Flows From Operating Activities:        
Net loss  $(13,988,216)  $(5,244,915)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:          
Depletion, depreciation and amortization   210,861    150,101 
Accretion of asset retirement obligation   374    - 
Bad debt   26,652    - 
Stock based compensation   2,515,238    2,380,051 
Warrant amendment expense   18,207    - 
Amortization of debt issue costs   954,845    - 
Write off of goodwill   32,787    - 
Accretion of debt discount   1,779,389    1,252,330 
Impairment of oil and gas assets   3,697,924    753,865 
Loss on abandonment of oil and gas assets   1,042,975    - 
Gain on settlement of liabilities   (108,600)   - 
Gain on sale of oil and gas interests   (450,000)   (275,000)
Change in fair value of derivative liabilities   52,154    (516,880)
Changes in operating assets and liabilities:          
(Increase) decrease in:          
Accounts receivable   (269,149)   90,366 
Prepaid expenses   36,771    36,032 
Inventory   -    24,067 
Deposits   (51,003)   (25)
Increase (decrease) in:          
Accounts payable and accrued liabilities   (228,456)   484,957 
Due to former officer   (799,000)   799,000 
Net Cash Used In Operating Activities   (5,526,247)   (66,051)
           
Cash Flows From Investing Activities:          
Cash received from acquisition of Richfield Oil & Gas, Inc.   6,011    - 
Purchase of oil and gas properties   (5,370,658)   (1,163,927)
Proceeds from sale of oil and gas interests   450,000      
Proceeds from sale of oil and gas properties   -    815,000 
Purchase of vehicles   (36,000)   - 
Purchase of furniture and equipment   (6,222)   (2,314)
Cash Provided to Richfield Oil & Gas, Inc.   (4,469,872)   - 
Net Cash Used In Investing Activities   (9,426,741)   (351,241)
           
Cash Flows From Financing Activities:          
Proceeds from notes payable   400,000    1,630,000 
Repayments on notes payable   (188,859)   (688,750)
Proceeds from convertible notes payable   18,002,210    - 
Debt issuance costs paid in cash   (1,932,199)   - 
Sale of common stock for cash   -    35,000 
Purchase of treasury stock   -    (25,000)
Net Cash Provided By Financing Activities   16,281,152    951,250 
           
Net change in cash   1,328,164    533,958 
           
Cash at beginning of period   609,061    75,103 
           
Cash at end of period  $1,937,225   $609,061 
           
Supplemental disclosures of cash flow information:          
Cash paid for interest  $1,140,104   $65,217 
Cash paid for taxes  $-   $- 
           
Supplemental disclosure of non-cash investing and financing activities:          
           
Conversion of notes payable and accrued interest to common stock  $-   $36,000 
Issuance of common stock and warrants for acquisition of Richfield Oil & Gas, Inc.  $8,605,287   $- 
Issuance of common stock to settle liabilities  $196,200   $- 
Purchase of property for common stock  $-   $18,000 
Original issue discount on notes payable  $160,000   $904,000 
Original issue discount on convertible notes payable  $4,028,285   $- 
Debt issuance costs paid in the form of warrants  $903,917   $- 
Debt issuance costs accrued  $6,107   $- 
Increase in asset retirement obligation  $3,822   $- 
Vehicles purchased through issuance of notes payable  $53,365   $- 
Capitalized oil and gas properties included in accounts payable  $438,760   $- 
Reclass convertible note to demand note  $-   $36,000 

 

See accompanying notes to the consolidated financial statements.

 

F-7
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

Note 1 Nature of Operations and Basis of Presentation:

 

Nature of Operations

 

Stratex Oil & Gas Holdings, Inc. (“we or the “Company”) was incorporated on August 15, 2003 as Poway Muffler and Brake Inc. in California to enter the muffler and brake business.  On December 15, 2008, a merger was effected with Ross Investments Inc., a Colorado shell corporation.    Ross Investments was the acquirer and the surviving corporation.  Ross Investments Inc. then changed its name to Poway Muffler and Brake, Inc. On May 25, 2012, we filed an Amendment to our Certificate of Incorporation by which we changed our name from Poway Muffler and Brake, Inc., a Colorado corporation, to Stratex Oil & Gas Holdings, Inc., with the Secretary of the State of Colorado.

 

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

 

On December 1, 2014, pursuant to the terms and condition of the Agreement and Plan of Merger dated May 6, 2014 by and among Stratex Oil & Gas Holdings, Inc. (the “Company”), Richfield Acquisition Corp. (“Merger Sub”), and Richfield Oil & Gas Company (“Richfield”), as amended by Amendment No. 1 to Agreement and Plan and Merger dated July 17, 2014 (the Agreement and Plan of Merger, as so amended, the “Merger Agreement”), Merger Sub merged with and  into Richfield, with Richfield continuing as the surviving corporation and as a wholly owned subsidiary of Stratex (the “Richfield Merger”). 

 

The Company is engaged in the sale of oil and gas and the exploration for and development of oil and gas reserves in Texas, Kansas, North Dakota, Montana, and Utah.

 

Basis of Presentation

 

The accompanying consolidated financial statements and related notes have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and include the accounts of the Company and its wholly-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

 

Note 2 Summary of Significant Accounting Policies:

 

Principles of Consolidation and Presentation

 

The accompanying consolidated financial statements and related notes have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and include the accounts of the Company and its wholly-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

 

Reclassification

 

Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation.   These reclassifications had no effect on reported losses.

 

Use of Estimates

 

The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Such estimates and assumptions impact, among others, the following: allowance for bad debt, 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 consolidated 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.

 

F-8
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

The accompanying consolidated 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.

 

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 an original maturity of three months or less to be cash equivalents.  There were no cash equivalents at December 31, 2014 and 2013.

 

The Company minimizes its credit risk associated with cash by periodically evaluating the credit quality of its primary financial institution. The balance at times may exceed federally insured limits.

 

F-9
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

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, 2014 and 2013, the allowance for doubtful accounts was $0.

 

Oil and Gas Properties, Successful Efforts Method

 

The Company accounts for oil and gas properties by the successful efforts method. Under this method of accounting, 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 FASB 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.  During the year ended December 31, 2014 and 2013, the Company recorded impairments on oil and gas assets of $3,697,924 and $753,865, respectively.

 

The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and natural gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain the Company’s wells and related equipment and facilities.

   

Depletion of producing oil and gas properties is recorded based on units of production. Acquisition costs of proved properties are depleted on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are depleted on the basis of proved developed reserves. As more fully described below, proved reserves are estimated by the Company’s independent petroleum engineer and are subject to future revisions based on availability of additional information.  Asset retirement costs are recognized when the asset is placed in service, and are depleted over proved reserves using the units of production method. 

 

Oil and gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. The Company compares net capitalized costs of proved oil and gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect the Company’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows based on management’s expectations of future oil and natural gas prices.

 

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. We perform periodic assessment of individually significant unproved crude oil and gas properties for impairment on a quarterly basis and we would recognize a loss at the time if there was an impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploratory activity on adjacent leaseholds, our management and geologists’ evaluation of the lease, and the remaining months in the lease term. As of December 31, 2014 and 2013, the Company does not have unproved properties whose acquisition costs are not significant. Thus, all unproven properties were assessed for impairment and the Company recorded an impairment allowance for expiring leases for the years ended December 31, 2014 and 2013.

 

F-10
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

The sale of a partial interest in a proved oil and gas property is accounted for as normal retirement and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production depletion rate. If the units-of-production rate is significantly affected, then the sale shall be accounted for as the sale of an asset, and a gain or loss shall be recognized. The unamortized cost of the property or group of properties shall be apportioned to the interest sold and the interest retained on the basis of the fair values of those interests. A gain or loss is recognized for all other sales of producing properties and is included in the results of operations. The sale of a partial interest in an unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to recovery of the cost applicable to the interest retained. A gain on the sale is recognized to the extent the sales price exceeds the carrying amount of the unproved property. A gain or loss is recognized for all other sales of nonproducing properties and is included in the results of operations. 

 

Support Facilities and Equipment

 

Support facilities and equipment include property and equipment that are not oil and gas properties and are recorded at cost and depreciated using the straight-line method over their estimated useful lives of five to ten years.  Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred.  Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable.  Our support facilities and equipment are generally located in proximity to certain of our principal fields.

 

Proved Reserves

 

Estimates of the Company’s proved reserves included in this report are prepared in accordance with U.S. 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 FASB 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, 2014 and 2013, the Company’s obligations were $639,349 and $34,000, respectively.  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. Accretion of asset retirement costs were immaterial for the years ended December 31, 2014 and 2013.

 

F-11
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

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 debt issued 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. For certain debt the original issue discount exceeded face value bringing the carrying value to $0 and the remainder charged to interest expense.

 

Beneficial Conversion Feature

 

For conventional convertible debt where the rate of conversion is below market value, the Company records a “beneficial conversion feature” (“BCF”) and related debt discount.

 

When the Company records a BCF the relative fair value of the BCF would be recorded as a debt discount against the face amount of the respective debt instrument. The debt discount attributable to the BCF is amortized over the period from issuance to the date that the debt matures.

 

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.

 

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.

 

F-12
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

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 follows 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 consolidated 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. After review of the Company’s tax positions, no liabilities were recorded for unrecognized tax benefits as of December 31, 2014 or December 31, 2013.

 

Earnings Per Share

 

Basic earnings (loss) per share is computed by dividing net income (loss) by the 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.

 

The Company had the following potential common stock equivalents at December 31, 2014:

 

Convertible debt – face amount of $21,657,939, conversion price of $0.25 - $2.50   73,782,461 
Common stock options, exercise price of $0.08 - $0.50   15,225,000 
Common stock warrants, exercise price of $0.15 - $5.00   33,450,677 
Total common stock equivalents   122,458,138 

 

The Company had the following potential common stock equivalents at December 31, 2013:

 

Convertible debt – face amount of $216,000, conversion price of $0.70   308,571 
Common stock options, exercise price of $0.08 - $0.50   8,975,000 
Common stock warrants, exercise price of $0.15 - $0.85   9,306,250 
Common stock to be issued   2,770,000 
Total common stock equivalents   21,359,821 

 

Since the Company reflected a net loss in 2014 and 2013, 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-13
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

Fair Value of Financial Instruments

 

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

 

The three levels of the fair value hierarchy are as follows:

 

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.

 

Financial assets and liabilities 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 Level 3 financial liabilities consist of the derivative warrants 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.

 

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.

 

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 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.

 

F-14
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

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

December 31, 2014  Fair Value Measurement Using 
   Level 1   Level 2   Level 3   Total 
Derivative warrant liabilities  $-   $-   $128,829   $128,829 

 

December 31, 2013  Fair Value Measurement Using 
   Level 1   Level 2   Level 3   Total 
Derivative warrant liabilities  $-   $-   $76,675   $76,675 

 

The table below provides a summary of the changes in fair value, including net transfers in and/or out, of all financial instruments measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period January 1, 2012 to December 31, 2013:

 

   Fair Value
Measurement Using
Level 3 Inputs
 
   Derivative Liabilities   Total 
         
Balance, January 1, 2013  $593,555   $593,555 
           
Purchases, issuances and settlements   -    - 
           
Total gains or losses (realized/unrealized) included in net loss   (516,880)   (516,880)
           
Transfers in and/or out of Level 3   -    - 
           
Balance, December 31, 2013  $76,675   $76,675 

 

Purchases, issuances and settlements          
           
Total gains or losses (realized/unrealized) included in net loss   52,154    52,154 
           
Transfers in and/or out of Level 3          
           
Balance, December 31, 2014  $128,829    128,829 

 

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

 

For periods in which impairment charges have been incurred, the Company is required to write down the value of the impaired asset to its estimated fair value. The initial measurement of these assets at fair value is calculated using discounted cash flow techniques and based on estimates of future revenues and costs. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include the Company’s estimate of future crude oil and natural gas prices, production costs, development expenditures, and anticipated production of proved and probable reserves, appropriate risk-adjusted discount rates and other relevant data. The Company recorded total impairment losses of $4,740,899 and $753,865 for the years ended December 31, 2014 and 2013, respectively.

 

F-15
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

Jumpstart Our Business Startups Act (“JOBS Act”), adopted January 3, 2012

 

We qualify as an “emerging growth company,” as defined in Section 2(a) of the Securities Act as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As such, we are permitted to rely on exemptions from various reporting requirements including, but not limited to, the requirement to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes–Oxley Act of 2002, and the requirement to submit certain executive compensation matters to shareholder advisory votes such as “say on pay” and “say on frequency.”

 

In addition, Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to take advantage of the benefits of this extended transition period. Our financial statements may therefore not be comparable to those of companies that comply with such new or revised accounting standards.

 

We will remain an emerging growth company up to the fifth anniversary of our first registered sale of common equity securities, or until the earliest of (a) the last day of the first fiscal year in which our annual gross revenues exceed $1 billion, (b) the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Exchange Act, which would occur if the market value of our common stock held by non-affiliates exceeds $700 million as of the last business day of our most recently completed second fiscal quarter, or (c) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period.

 

F-16
 

 

Recent Accounting Pronouncements

 

From time to time, new accounting pronouncements are issued by the FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.

 

In May 2014, the Financial Accounting Standards Board issued accounting guidance on revenue recognition. The amended guidance will enhance the comparability of revenue recognition practices and will be applied to all contracts with customers. Improved disclosures related to the nature, amount, timing, and uncertainty of revenue that is recognized are requirements under the amended guidance. This guidance will be effective for fiscal 2017 and will be required to be applied retrospectively. We are currently assessing the impact that this guidance will have on our financial statements at this time.

 

In August 2014, the Financial Accounting Standards Board issued ASU No. 2014-15. This standard provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. This ASU is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2016, with early adoption permitted. The Company is evaluating the new guidance and plans to provide additional information about its expected impact at a future date.

 

In April 2015, the Financial Accounting Standards Board issued ASU No. 2015-03. This standard provides guidance on the balance sheet presentation for debt issuance costs and debt discounts and debt premiums. To simplify the presentation of debt issuance costs, this standard requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. This ASU is effective for fiscal years beginning after December 15, 2015. The Company is evaluating the new guidance and plans to provide additional information about its expected impact at a future date.

 

Note 3 Going Concern:

 

The Company’s consolidated financial statements have been prepared on a going concern basis which contemplates the realization of assets and the liquidation of liabilities in the ordinary course of business. The Company has incurred substantial losses from operations causing negative working capital, in that current liabilities exceed current assets, and the Company has negative operating cash flows, which raise substantial doubt about the Company’s ability to continue as a going concern. As reflected in the accompanying consolidated financial statements, the Company has a net loss of $13,988,216 and net cash used in operations of $5,526,247 for the year ended December 31, 2014 and has a working capital deficit of $2,435,050 at December 31, 2014.

 

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. These uncertainties create substantial doubt about the Company’s ability to continue as a going concern.

 

The accompanying consolidated 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 consolidated 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-17
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

Note 4 Acquisition of Richfield Oil & Gas Company:

 

On December 1, 2014, the Company acquired Richfield Oil & Gas Company (Richfield) by merging a wholly owned subsidiary of the Company with and into Richfield, with Richfield continuing as the surviving corporation and wholly owned subsidiary of the Company. Richfield is involved in the exploration and production of crude oil and natural gas. Richfield’s asset base, technical capabilities and operating expertise, together with the Company’s project management, operational skills and financial capacity, should enable effective development of oil and gas reserves. At December 1, 2014, each share of Richfield common stock was exchanged for one share of common stock of the Company and each outstanding warrant to purchase Richfield common stock was exchanged for one warrant to purchase a share of the Company’s common stock.

 

The components of the consideration transferred follow:    
     

Consideration attributable to stock issued (1)

  $8,183,220 

Consideration attributable to exchanged warrants (2)

   422,067 
Consideration attributable to settlement of accounts and notes receivable (3)   4,645,463 
Total consideration transferred  $13,250,750 

 

(1) The fair value of the Company’s common stock on the acquisition date was $0.135 per share based on the closing value on the NASDAQ OTC. The Company issued 60,616,448 shares of stock for the acquisition of Richfield.

 

(2) The fair value of warrants issued by the Company on the acquisition to former warrant holders of Richfield.

 

(3) The fair value of a note receivable and accounts receivables to the Company from Richfield that was settled upon the acquisition.

 

The following table summarizes the assets acquired and liabilities assumed as of the acquisition date. The Company is in the process of obtaining additional valuation evidence, including appraisals and other market transactions, as it relates to certain oil and gas properties and other long-lived assets. Therefore, the provisional measurements for these amounts are subject to change.

 

Cash and cash equivalents  $6,011 
Accounts receivable   188,887 
Other current assets   140,439 
Proven oil and gas properties (1)   8,145,486 
Unproven oil and gas properties (2)   9,930,578 
Well equipment   2,072,166 
Furniture and equipment   38,205 
Goodwill (3)   32,787 
Total assets acquired   20,554,559 
      
Accounts payable and accrued liabilities   2,500,473 
Notes and loans payable (4)   4,114,183 
Asset retirement obligations   601,153 
Capital lease obligations   88,000 
Total liabilities assumed   7,303,809 
      
Net assets acquired  $13,250,750 

 

(1) Proven oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included Richfield resources, assumed future production profiles, commodity prices (mainly based on observable market inputs), discount rate of 15.0 percent, risk adjustments of classes of reserves between 10.0% and 100.0% and assumptions on the timing and amount of future development and operating costs.

 

F-18
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

(2) Unproven oil and gas properties were measured primarily using a market approach with internal management inputs based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs include estimated price per acre, potential future production and assumptions on the timing and amount of future development and operating costs.

 

(3) Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is not amortized and is not deductible for tax purposes.

 

(4) Notes and loans payable and capital lease obligations were recognized mainly at market rates at closing (Level 1).

 

The following table presents revenues and earnings for Richfield for the period presented:

 

   Acquisition Date 
   Through 
   December 31, 2014 
     
Revenues  $103,638 
Earnings  $(917,187)

 

Pro Forma Impact of Richfield Merger. The following table presents unaudited pro forma information for the Company as if the merger of Richfield had occurred at the beginning of each year presented:

 

   2014   2013 
Revenues  $2,187,958   $1,893,593 
Net loss  $(24,102,174)  $(12,034,499)
Loss per common share  $(0.22)  $(0.11)

 

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the merger and factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the consolidated results of operations actually would have been had the merger been completed on January 1, 2014, or on January 1, 2013. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the combined company. The unaudited pro forma consolidated results reflect pro forma adjustments for depletion and depreciation expense related to the fair value adjustment to oil and gas properties, and elimination of interest expense related to the loan from Stratex.

 

F-19
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

Note 5 Oil and Gas Assets:

 

The following table summarizes the Company’s oil and gas assets, net:

 

Balance – January 1, 2013  $2,527,249 
Additions   1,141,503 
Depletion   (98,335)
Impairment   (753,865)
Abandonments   - 
Dispositions   (540,000)
      
Balance – December 31, 2013   2,276,552 
Additions   23,377,139 
Depletion   (163,095)
Asset retirement obligations   36,238 
Impairment   (3,697,924)
Abandonments   (1,042,975)
Dispositions   - 
Balance – December 31, 2014  $20,785,935 

 

The Company owns support facilities and equipment which serve its oil and gas production activities. The following table summarizes the properties and equipment, net:

 

Balance – January 1, 2013  $114,495 
Additions   40,424 
Depreciation   (16,838)
Impairment   - 
      
Balance – December 31, 2013   138,081 
Additions   2,578,822 
Depreciation   (64,193)

Dispositions

   (439)
Balance – December 31, 2014  $2,652,271 

  

In July 2013, we entered into an Assignment and Conveyance Agreement (the “Agreement”) with Oasis Petroleum North America, LLC. (“Oasis”). Pursuant to the Agreement, we sold certain oil & gas property located in Roosevelt, Montana to Oasis for consideration of $215,000 cash. We recognized a gain on the sale of $215,000 in the year ended December 31, 2013.

 

On July 1, 2013, we entered into a Purchase & Sale Agreement (the “Agreement”) with Nebraska Alliance Resources, LLC. (“Nebraska”). Pursuant to the Agreement, we sold certain oil & gas property located in Sioux County, Colorado to Nebraska for consideration of $600,000 cash. We recognized a gain on the sale of $60,000 in the year ended December 31, 2013.

 

On March 14, 2014, we entered into a Purchase & Sale Agreement Option (the “Agreement”) to sell certain oil & gas property interests located in Weld, Colorado with Prime Meridian Oil & Gas, LLC (the “Purchaser”). The sale was completed on March 31, 2014. We recognized a gain on the sale of $450,000 during the year ended December 31, 2014.

 

During the year ended December 31, 2014, the Company abandoned certain working and net revenue interests in oil and gas property located in Callahan County, Texas and Sumner County, Kansas. In connection with the abandonment, the Company recognized losses totaling $1,042,975.

 

As of December 31, 2014 and 2013, the Company had $163,095 and $98,335, respectively to depletion expense.

 

F-20
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

Note 6 Vehicles, Furniture and Equipment:

 

The following table summarizes furniture and equipment, net:

 

Balance – January 1, 2013  $994 
Additions   2,314 
Depreciation   (928)
Impairment   - 
      
Balance – December 31, 2013   2,380 
Additions   133,792 
Depreciation   (13,863)
Impairment   - 
Balance – December 31, 2014  $122,309 

 

During years ended December 31, 2014 and 2013, the Company recorded $13,863 and $928, respectively to depreciation expense.

 

Note 7 Demand Notes Payable:

 

As of December 31, 2013, three (3) convertible notes for an aggregate principal amount of $216,000 had become due and were in default. These notes were reclassified and are recorded as due on demand. During the year ended December 31, 2014, two (2) of these notes in the aggregate principal amount of $96,000 were repaid in full. The balance due to the remaining note holder as of December 31, 2014 was $120,000 and is convertible into shares of common stock at a conversion rate of $0.70 per share.

 

As part of the merger with Richfield, on December 1, 2014, the Company agreed to assume two (2) convertible notes in the aggregate principal amount of $52,560 and $150,015. The notes bear interest at 12.0% and 10.0% per annum and are convertible into shares of common stock at a conversion rate of $2.50 and $0.60 per share, respectively. These notes have become due and are currently in default. They have been reclassified and are recorded as due on demand as of December 31, 2014.

 

Note 8 Notes Payable:

 

(A)   Promissory Note

 

On May 11, 2013 a promissory note issued in 2012 with principal of $288,750 matured and a new promissory note with principal of $288,750 was issued. This was considered a substantial modification of terms and the Company applied extinguishment accounting. The note bore interest at 12% per annum and was to be due in interest only payments for the first 24 months.  Although the note did not mature until May 10, 2015, it was paid in full on August 29, 2013.  In addition, the Company issued the note holder a five (5) year common stock purchase warrant exercisable for up to 375,000 shares of common stock at $0.85 per share. The issuance of the warrants was recorded as interest expense on the date of issuance.  The note was secured by certain oil and gas assets of the Company.

 

Extinguishment Accounting

 

The Company compared the fair value of the note on the date of modification to the as-modified note.  Because the fair value of the as-modified note was 10% greater than the fair value of the existing note, the Company applied extinguishment accounting, resulting in a loss on extinguishment of debt of $411,030, for the year ended December 31, 2013. The Company recorded the loss as interest expense in the Statement of Operations.

 

F-21
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

(B)   Promissory Note

 

On March 15, 2013, the Company issued a promissory note with principal of $400,000 for proceeds of $400,000.  The note bore interest at 12% per annum with interest only payments for the first 24 months.  The note was to mature on March 14, 2015.  In addition, the Company issued the note holder a five (5) year common stock purchase warrant exercisable for up to 500,000 shares of common stock at $0.85 per share. The issuance of the warrants was recorded as a debt discount up to the face amount of the note.  The amount in excess of the face amount of the note was recorded to interest expense on the date of issuance. The note was secured by certain oil and gas assets of the Company. On August 26, 2013 the note was paid off.

 

(C)   Promissory Note

 

On May 20, 2013, the Company issued a promissory note with principal of $80,000 for proceeds of $80,000.  The note bears interest at 12% per annum and will be due in interest only payments for the first 24 months.  The note matures on May 19, 2015.  In addition, the Company issued the note holder a five (5) year common stock purchase warrant exercisable for up to 100,000 shares of common stock at $0.85 per share to an accredited investor. The issuance of the warrants was recorded as a debt discount up to the face amount of the note.  The amount in excess of the face amount of the note was recorded to interest expense on the date of issuance. The note is secured by certain oil and gas assets of the Company.

 

(D)   Promissory Note

 

On May 20, 2013, the Company issued a promissory note with principal of $25,000 for proceeds of $25,000.  The note bears interest at 12% per annum and will be due in interest only payments for the first 24 months.  The note matures on May 19, 2015.  In addition, the Company issued the note holder a five (5) year common stock purchase warrant exercisable for up to 31,250 shares of common stock at $0.85 per share. The issuance of the warrants was recorded as a debt discount up to the face amount of the note.  The amount in excess of the face amount of the note was recorded to interest expense on the date of issuance. The note is secured by certain oil and gas assets of the Company.

 

(E) Promissory Note

 

On July 1, 2013, the Company issued a promissory note with principal of $100,000 for proceeds of $100,000.  The note bears interest at 12% per annum and will be due in interest only payments for the first 36 months.  The note matures on July 1, 2016.  In addition, the Company issued the note holder a five (5) year common stock purchase warrant exercisable for up to 125,000 shares of common stock at $0.85 per share. The issuance of the warrants was recorded as a debt discount up to the face amount of the note.  The amount in excess of the face amount of the note was recorded to interest expense on the date of issuance. The note is secured by certain oil and gas assets of the Company. On July 16, 2014 the note was paid off.

 

(F) Promissory Note

 

On October 1, 2013, the Company issued a promissory note with principal of $500,000 for proceeds of $500,000.  The note bears interest at 12% per annum and will be due in interest only payments for the first 36 months.  The note matures on September 30, 2016.  In addition, the Company issued the purchaser, 1,000,000 shares of the common stock of the Company. The issuance of the shares was recorded as a debt discount equal to the market value of shares issued ($140,000) at issuance date.

 

(G)   Promissory Note

 

On December 5, 2013, the Company issued a promissory note with principal of $500,000 for proceeds of $500,000.  The note bears interest at 12% per annum and will be due in interest only payments for the first 36 months.  The note matures on December 4, 2016.  In addition, the Company issued the purchaser, 1,000,000 shares of the common stock of the Company. The issuance of the shares was recorded as a debt discount equal to the market value of shares issued ($150,000) at issuance date.

 

F-22
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

(H)   Promissory Note

 

On December 12, 2013, the Company issued a promissory note with principal of $25,000 for proceeds of $25,000.  The note bears interest at 12% per annum and will be due in interest only payments for the first 36 months.  The note matures on December 11, 2016.  In addition, the Company issued the purchaser, 50,000 shares of the common stock of the Company. The issuance of the shares was recorded as a debt discount equal to the market value of shares issued ($9,000) at issuance date.  

 

(I)   Promissory Note

 

On January 27, 2014, the Company issued a promissory note with principal of $400,000 for proceeds of $400,000.  The note bears interest at 12% per annum and will be due in interest only payments for the first 36 months.  The note matures on January 27, 2017.  In addition, the Company issued the purchaser, 800,000 shares of the common stock of the Company. The issuance of the shares was recorded as a debt discount equal to the market value of shares issued ($160,000) at issuance date.  

 

(J)   Promissory Notes

 

On February 14, 2014 and September 25, 2014, the Company issued promissory notes in the principal amount of $28,510 and $24,855, respectively, for the purchase of two vehicles.  Monthly principal and interest payments are $599 and $450, respectively. The notes bear interest at 9.49% and 9.13% per annum and mature on February 13, 2019 and September 7, 2020, respectively.  The notes are each secured by a vehicle.

 

(K)   Promissory Note

 

On December 1, 2014 as part of the merger with Richfield, the Company assumed a promissory note in the amount of $578,454. The note bears interest at 10% per annum with monthly principal and interest payments in the amount of $15,000.  The note matures on June 30, 2015.

 

Notes payable as of December 31, 2014 is as follows:

 

   December 31,
2014
 
     
Notes payable  $2,143,959 
Discount on notes   (314,388)
Notes payable, net of debt discount   1,829,571 
Less: Current maturities   (573,094)
      
Notes payable, net of debt discount and current maturities  $1,256,477 

 

Future minimum debt repayments under these obligations at December 31, 2014 are as follows:

 

Year ending December 31:    
     
2015  $678,357 
2016   1,034,506 
2017   410,116 
2018   11,103 
2019 and thereafter   9,878 
   $2,143,959 

 

F-23
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

Note 9 Convertible Notes Payable:

 

(A)  Series A Senior Secured Convertible Promissory Notes

 

From February 11, 2014 through April 10, 2014, the Company raised gross proceeds of $9,987,650 through the sale of units (the “Series A Units”) in a private offering (the “Series A Offering”). The purchase price for each Series A Unit was $50,000 and each Series A Unit consisted of (i) a 12% Series A Senior Secured Convertible Promissory Note in the principal amount of $50,000 (the “Series A Notes”) convertible into shares of common stock of the Company at a conversion price of $0.30 per share and (ii) a Series A warrant to purchase 33,333 shares of common stock of the Company at an exercise price of $0.30 per share (the “Series A Warrant”). All outstanding principal and interest of each Series A Note is due on February 11, 2016. The Series A Notes may be redeemed by the Company at any time following six (6) months after their respective issuance. If however, the Company elects to redeem the Series A Notes prior to the one (1) year anniversary date of the issuance of such Series A Note, the Company shall pay the holder all unpaid interest on the portion of the principal redeemed that would have been earned through such one (1) year anniversary date. The holder of each Series A Note may elect to convert the principal balance of the Series A Note into shares of common stock at any time following six (6) months after the issuance of such note.

 

The Series A Notes are secured by a first lien on substantially all of the assets of the Company, including all present and future wells and working interests, on a pro-rata basis.

 

Each Series A Note bears interest at 12% per annum and is due and payable quarterly, in arrears, with the initial interest payment due March 31, 2014.

 

Beneficial Conversion Feature

 

The intrinsic value of certain convertible notes, when issued, gave rise to a beneficial conversion feature which was recorded as a discount to the notes of $1,613,642 to be amortized over the period from issuance to the date that the debt matures.

 

Warrants

 

Each investor participating in the Series A Offering received a Series A Warrant, exercisable for up to 33,333 shares of common stock for every $50,000 invested. The Series A Warrants are exercisable at $0.30 per share. The Series A Warrants expire five (5) years from the date of issuance. During the year ended December 31, 2014, we issued Series A Warrants exercisable for up to 6,658,374 shares of our common stock to investors participating in the Series A Offering. The issuance of the Series A Warrants was recorded as a debt discount of $1,424,236 and is being amortized over the life of the Series A Note.

 

(B)  Series B Senior Secured Convertible Promissory Notes

 

From June 6, 2014 through August 20, 2014, the Company raised gross proceeds of $8,014,560 through the sale of units (the “Series B Units”) in a private offering (the “Series B Offering”). The purchase price for each Series B Unit was $50,000 and each Series B Unit consisted of (i) a 12% Series B Senior Secured Convertible Promissory Note in the principal amount of $50,000 (the “Series B Notes”) convertible into shares of common stock of the Company at a conversion price of $0.30 per share and (ii) a Series B warrant to purchase 33,333 shares of common stock of the Company at an exercise price of $0.30 per share (the “Series B Warrant”). All outstanding principal and interest of each Series B Note is due on June 6, 2016. The Series B Notes may be redeemed by the Company at any time following six (6) months after their respective issuance. If however, the Company elects to redeem the Series B Notes prior to the one (1) year anniversary date of the issuance of such Series B Note, the Company shall pay the holder all unpaid interest on the portion of the principal redeemed that would have been earned through such one (1) year anniversary date. The holder of each Series B Note may elect to convert the principal balance of the Series B Note into shares of common stock at any time following six (6) months after the issuance of such note.

 

F-24
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

The Series B Notes are secured by a first lien on substantially all of the assets of the Company, including all present and future wells and working interests, on a pro-rata basis. The lien is pari-passu with the lien granted in favor of the holders of the Company’s outstanding Series A Notes.

 

Each Series B Note bears interest at 12% per annum and is due and payable quarterly, in arrears, with the initial interest payment due September 30, 2014.

 

Warrants

 

Each investor participating in the Series B Offering received a Series B Warrant, exercisable for up to 33,333 shares of common stock for every $50,000 invested. The Series B Warrants are exercisable at $0.30 per share. The Series B Warrants expire five (5) years from the date of issuance. During the six months ended June 30, 2014, we issued Series B Warrants exercisable for up to 5,342,742 of our common stock to investors participating in the Series B Offering. The issuance of the Series B Warrants was recorded as a debt discount of $990,408 and is being amortized over the life of the Series B Note.

 

(C)  Other Convertible Promissory Notes

 

As part of the merger with Richfield, on December 1, 2014, the Company agreed to assume two (2) convertible notes in the aggregate principal amount of $138,182 and $3,194,972. Both notes bear interest at 12.0% per annum and are convertible into shares of common stock at a conversion rate of $0.25 per share. The notes mature on May 31, 2105 and June 30, 2016 respectively.

 

The following is a summary of Convertible Notes Payable:

 

Balance – January 1, 2014  $- 
Issuance of convertible notes payable   18,002,210 
Discount recorded on beneficial conversion feature at issuance   (1,613,642)
Discount recorded on warrants at issuance   (2,414,643)
Assumption of convertible notes payable from merger   3,333,154 
Accretion of debt discount   1,494,256 
Convertible notes payable, net of debt discount   18,801,335 
Less current maturities   (138,132)
Balance – December 31, 2014  $18,663,203 

 

Future minimum debt repayments under these obligations at December 31, 2014 are as follows:

 

Year ending December 31:    
     
2015  $138,182 
2016   21,197,182 
2017 and thereafter   - 
   $21,335,364 

 

F-25
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

(D)   Debt Issuance Costs

 

Debt issuance costs, net are as follows:

 

Balance - January 1, 2014  $- 

Debt issuance costs incurred in 2014

   2,845,541 

Amortization of debt issuance costs

   (958,163)
Balance – December 31, 2014  $1,887,378 

 

Note 10 Stockholders’ Equity:

 

(A)  

Preferred Stock

 

Pursuant to the Company’s Agreement and Plan of Merger with Richfield Oil & Gas Company (“Richfield”), dated as of May 6, 2014 (the “Merger Agreement”), the exchange of all outstanding shares of our Series A Preferred Stock for 7,000,000 shares of our common stock is a condition to the Company’s and Richfield’s obligation to effect the merger. Each share of our Series A Preferred Stock entitles the holder thereof to cast 1,000,000 votes on all matters submitted to a vote of the stockholders. Accordingly, on August 20, 2014, our board of directors (the “Board”) approved the issuance of 7,000,000 shares of our common stock to Rotary Partners LLC, an entity in which Stephen Funk, our Chief Executive Officer, owns and controls one hundred percent (100%) of the membership interests. Such shares were issued in exchange for the surrender by Rotary Partners of 60 shares (constituting all) of the Company’s outstanding Series A Preferred Stock. Previously, such shares of Series A Preferred Stock had been issued to Mr. Funk who transferred them to Rotary Partners on August 19, 2014.

 

During the year ended December 31, 2013, the Company issued 10 shares of preferred stock held in Treasury.

 

Transaction Type  Quantity of Shares   Valuation   Range of Value per Share 
Services rendered – officers   10   $830   $83.00 
Total   10   $830   $83.00 

 

(B)   Common Stock

 

During the year ended December 31, 2014, the Company issued the following common stock:

 

Transaction Type  Quantity of Shares   Valuation   Range of Value per Share 
Common stock issued to settle liabilities   270,000   $102,600   $0.38 
Common stock issued for preferred stock   7,000,000    --    -- 
Common stock issued for services   1,625,180    

531,854

     0.23-0.36   
Common stock issued with promissory notes   850,000    170,000    0.20 
Common stock issued in connection with Richfield Merger   60,616,448    8,183,220    0.14 
Total   

70,361,628

   $

8,987,674

   $0.14-0.38 

 

During the year ended December 31, 2014, the Company granted common stock to a consultant for future services. The Company recognizes the fair value of the shares in the statement of operations in the period earned. As of December 31, 2014, the Company has $25,146 in stock compensation related to common stock issuance that is yet to be earned.

 

F-26
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

During the year ended December 31, 2013, the Company issued the following common stock:

 

Transaction Type  Quantity of Shares   Valuation   Range of Value per Share 
Common stock issued for cash   70,000   $35,000   $0.50 
Common stock issued for services   140,000    35,000    0.25 
Conversion of debt and interest   51,249    36,000    0.70 
Common stock issued with promissory notes   2,000,000    290,000     0.14-0.15   
Common stock issued to acquire oil and gas assets   150,000    18,000    0.12 
Total   2,411,249   $414,000   $0.12-0.70 

 

(C) Warrants

 

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

 

   Warrants   Weighted Average Exercise Price 
         
Outstanding – January 1, 2013   2,075,000   $0.43 
Exercisable – January 1, 2013   2,075,000   $0.43 
Granted   7,321,250   $0.26 
Exercised   -   $- 
Forfeited/Cancelled   -   $- 
Outstanding – December 31, 2013   9,306,250   $0.30 
Exercisable – December 31, 2013   9,306,250   $0.30 
Granted   24,144,427   $0.36 
Exercised   -   $- 
Forfeited/Cancelled   -   $- 
Outstanding – December 31, 2014   33,450,677   $0.34 
Exercisable – December 31, 2014   33,450,677   $0.34 

 

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

 
$0.15 - $5.00     33,450,677   3.49 years   $ 0.34       33,450,677     $ 0.34  

 

At December 31, 2014 and December 31, 2013, the total intrinsic value of warrants outstanding and exercisable was $0 and $61,000, respectively.

 

During the year ended December 31, 2014 the Company re-priced warrants to purchase an aggregate of 875,000 common shares in the capital of the Company from an exercise price of $0.85 to an exercise price of $0.15. All other warrant terms remain the same including the expiration dates of March through May 2018.

 

The Company recorded interest expense related to the re-priced warrants of $14,755 during the year ended December 31, 2014 calculated as the fair value of the re-priced warrants minus the fair value of the warrants just prior to the re-pricing.

 

During the year ended December 31, 2014 the Company re-priced warrants to purchase an aggregate of 125,000 shares of common stock from an exercise price of $0.85 to an exercise price of $0.30. All other warrant terms remain the same including the expiration date of July 2018.

 

F-27
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

The Company recorded interest expense related to the re-priced warrants of $3,452 during the year ended December 31, 2014 calculated as the fair value of the re-priced warrants minus the current fair value of the warrants just prior to the re-pricing.

 

On December 1, 2014 the Company issued 7,011,561 new warrants to former Richfield warrant holders as per the merger agreement. The exercise price and expiration dates remained the same as the previous Richfield warrants. These new warrants were valued at their fair value using the Black-Scholes warrants valuation model and Stratex’s historical data. The calculated fair value of the warrants Stratex issued on closing was $422,067 or $0.06 per warrant.

 

During year ended December 31, 2013 the Company re-priced warrants to purchase an aggregate of 1,400,000 common shares in the capital of the Company from an exercise price of $1.65 to an exercise price of $0.30. All other warrant terms remain the same including the expiry date of October 31, 2017.

 

The Company recorded compensation expense related to the re-priced warrants of $27,427 during 2013 calculated as the fair value of the re-priced warrants minus the current fair value of the surrendered warrants.

 

On the dates of grant during the year ended December 31, 2014, the Company valued warrant issuances at fair value, utilizing a Black-Scholes option valuation model.  The Company utilized the following management assumptions:

 

Exercise price $0.30 – $0.37
Expected dividends 0%
Expected volatility 151% – 168%
Risk free interest rate 1.53% – 1.73%

Contractual life of warrants

5 years

 

On the dates of grant during the year ended December 31, 2013, the Company valued warrant issuances at fair value, utilizing a Black-Scholes option valuation model.  The Company utilized the following management assumptions:

 

Exercise price $0.15 – $1.65
Expected dividends 0%
Expected volatility 172%
Risk free interest rate 0.62% – 1.46%

Contractual life of warrants

3.9 years – 5 years

 

F-28
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

(D) Options

 

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

 

   Options   Weighted Average Exercise Price 
         
Outstanding – January 1, 2013   3,000,000   $0.50 
Exercisable – January 1, 2013   750,000   $0.50 
Granted   11,100,000   $0.13 
Exercised   -   $- 
Forfeited/Cancelled   (1,500,000)  $0.50 
Outstanding – December 31, 2013   12,600,000   $0.17 
Exercisable – December 31, 2013   8,975,000   $0.16 
Granted   5,250,000   $0.30 
Exercised   -   $- 
Forfeited/Cancelled   -   $- 
Outstanding – December 31, 2014   17,850,000   $0.21 
Exercisable – December 31, 2014   15,225,000   $0.19 

 

  Options Outstanding     Options Exercisable  
 

Range of

exercise price

 

Number

Outstanding

 

Weighted Average
Remaining

Contractual Life

(in years)

 

Weighted

Average

Exercise Price

   

Number

Exercisable

   

Weighted

Average

Exercise Price

 
  $0.08-$0.50     17,850,000   4.83 years   $ 0.21       15,225,000     $ 0.19  

 

At December 31, 2014, the total intrinsic value of options outstanding and exercisable was $0.

 

At December 31, 2013, the total intrinsic value of options outstanding and exercisable was $363,000 and $333,000, respectively.

 

During the year ended December 31, 2014, the Company's board of directors authorized the grant of 5,250,000 stock options, having a total fair value of approximately $1,170,503, with vesting periods ranging from immediate to 2.00 years. These options expire between April 2019 and September 2019.

 

As of December 31, 2014, the Company has $453,235 in stock-based compensation related to stock options that is yet to be vested. The weighted average expensing period of the unvested options is 0.65 years.

 

On the dates of grant during the year ended December 31, 2014, the Company valued option issuances at fair value, utilizing a Black-Scholes option valuation model.  The Company utilized the following management assumptions:

 

Exercise price $0.30– $0.39
Expected dividends 0%
Expected volatility 151% – 158%
Risk free interest rate 1.58%–1.80%
Expected life of options 2.5– 3.5 years
Expected forfeitures 0%

 

On the dates of grant during the year ended December 31, 2013, the Company valued option issuances at fair value, utilizing a Black-Scholes option valuation model.  The Company utilized the following management assumptions:

 

Exercise price $0.08 – $0.19
Expected dividends 0%
Expected volatility 172%
Risk free interest rate 1.66% – 2.69%
Expected life of options 3 years – 5 years
Expected forfeitures 0%

 

F-29
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

(E)   Treasury Stock

 

During the year ended December 31, 2014 150,000 shares of common stock was returned to the Company and retired. The stock was originally issued in November 2013 as partial consideration for working and net revenue interests in oil and gas property located in Callahan County, Texas.

 

During the year ended December 31, 2013, the Company repurchased 50 shares of preferred stock at cost of $25,000 and issued 10 shares of preferred stock from treasury for compensation.

 

Note 11 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.

 

In October 2013 Stratex filed an action against Timothy Kelly seeking damages against him for breach of fiduciary duty and usurpation of corporate opportunities in the Westchester County Superior Court Index No 67528/2013. On September 18, 2014, the Westchester County Superior Court of the State of New York (the “Court”) (i) awarded Stratex a judgment against Timothy Kelly (“Kelly”) in the amount of $3,164,000 (plus interest at the rate of 9% per annum) and (ii) dismissed “with prejudice”, all counterclaims previously asserted by Kelly against Stratex. Stratex intends to vigorously pursue the enforcement of the $3,164,000 judgment awarded to Stratex against Kelly.

 

In or about September 2014 Stratex filed an action against Eagleford Energy Zavala Corp. in the 293rd District Court of Zavala County, Texas. Known as Stratex Oil & Gas Holdings, Inc. v Eagleford Energy Zavala, Inc. Case No 14-09-132090-ZCV, the action was for foreclosure of the payment of obligations owed by Eagleford Energy Zavala Corp for lease obligations. Prior to foreclosure Eagleford paid the obligations which were owed. On March 31, 2015 this matter was settled by Stratex releasing its interest in the project for the development of the 2,926 acres in Zavala County, Texas to its two partners Eagleford Energy Zavala Corp and Quadrant Energy, Inc. The parties entered into a mutual release of all obligations.

 

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.

 

F-30
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

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 natural 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.

 

Employment Agreement

 

On April 11, 2014, the Company entered into an Executive Employment Agreement with Jeffrey Robinson to serve as the Director of Field Operations (DFO”). The terms of the Agreement are as follows:

 

Term - 3 years,
Compensation - $150,000 salary per annum, bonus eligibility,
Option Grant - 1,000,000 options to acquire restricted stock at an exercise price of $0.39 per share.

 

Employment Agreement

 

On May 6, 2014, the Company entered into an Executive Employment Agreement with Alan D. Gaines to serve as the Chairman of our Board of Directors. The terms of the Agreement are as follows:

 

Term - 5 years,
Compensation - $350,000 salary per annum, subject to 10% increase per annum,
Bonus Eligibility – Target Bonus equal to 100% of base salary based on performance criteria to be established

 

By virtue of Mr. Gaines joining the Board, options exercisable for up to 3,000,000 shares of our common stock, previously granted to him in December 2013, became fully vested. Such options are exercisable at $0.15 per share.

 

Employment Agreement

 

On August 8, 2014, the Company entered into an Employment Agreement with Matthew S. Cohen to serve as our Executive Vice President & General Counsel. On February 13, 2015, the Board of Directors of the Company, accepted the resignation of Mr. Cohen. The terms of the original employment Agreement were as follows:

 

Term - 4 years,
Compensation - $230,000 salary per annum, subject to 10% increase per annum,
Bonus Eligibility – Target Bonus equal to 80% of base salary based on performance criteria to be established
400,000 shares of restricted common stock
Option Grant - 2,000,000 options to acquire restricted stock at an exercise price of $0.30 per share. Such stock options vest over a 2 year period, expire in 5 years from the date of the grant and provides for cashless exercise and “piggy-back” registration rights.

 

Employment Agreement

 

On September 15, 2014, the Company entered into an Employment Agreement with Michael J. Thurz to serve as our Chief Administrative Officer. Since July 2014, Mr. Thurz has served as a member of our Board of Directors. The terms of the Agreement are as follows:

 

Term - 4 years,
Compensation - $200,000 salary per annum, subject to 10% increase per annum,
Option Grant - 1,500,000 options to acquire restricted stock at an exercise price of $0.30 per share. Such stock options vest over a 2 year period, expire in 5 years from the date of the grant and provides for cashless exercise and “piggy-back” registration rights.

 

F-31
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

Consulting Agreement

 

On May 1, 2014, the Company entered into a Consulting Agreement (the “IR Agreement”) with MZHCI, LLC to provide investor relations consulting services.  The terms of the IR Agreement are as follows:

 

Term - 1 year, commencing May 6, 2014, the IR Agreement shall renew and continue in effect for successive one-year periods unless terminated,
Compensation - $8,000 per month,
Common Share Grant – 200,000 restricted common shares issued immediately; An additional 200,000 restricted common shares at six month anniversary.
Reimbursement for all reasonable and necessary business expenses

 

Agreements with Placement Agents and Finders

 

The Company entered into a Financial Advisory and Investment Banking Agreement with Radnor Research & Trading Company, LLC (“Radnor”) effective January 24, 2014 (the “Radnor Advisory Agreement”). Pursuant to the Radnor Advisory Agreement, Radnor acted as the Company’s exclusive financial advisor and placement agent to assist the Company in connection with the two private placements of the Series A and Series B Convertible Promissory Notes.

  

During the year ended December 31, 2014 the Company paid to Radnor fees of $1,119,520 and issued Radnor 3,731,750 five year warrants with an exercise price of $0.30.

 

In addition to the fees paid to Radnor the Company incurred financing fees of $680,700 during the year ended December 31, 2014 to JD Partners Co., Ltd in relation to the 2014 private placements.

 

F-32
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

Note 12 Income Taxes:

 

The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with FASB ASC 740. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

 

The income tax expense for the years ended December 31, 2014 and 2013 consists of the following: 

 

    2014    2013 
Current income taxes  $-   $- 
Deferred income taxes   -    - 
Provision for income taxes  $-   $- 

 

The following is a reconciliation of the reported amount of income tax expense (benefit) on the statutory rate for the years ended December 31, 2014 and 2013 to the amount of income tax expenses that would result from applying the statutory rate to pretax income.

 

   2014   2013 
   %   % 
U.S. federal statutory rate   (34)   (31)
State income tax, net of federal benefit   (4)   (7)
Non-deductible stock compensation   6    22 
Change in fair value of derivative expense   -    4 
Amortization of debt discount and issuance costs   5    9 
Impairment loss   -    6 
Deferred tax true-up   -    (12)
Utilization of NOL   -    (2)
Other permanent differences   -    (1)
RTP   (8)   - 
Change in valuation allowance   34    12 
Other, net   1    0 
Income tax provision (benefit)   -    - 

 

F-33
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

At December 31, 2014 and 2013, the Company has net operating loss carry forwards for Federal income tax purposes of $16,755,450 and $3,300,000, respectively, which expire in varying amounts during the tax years 2017 through 2033.

 

The components of the Company’s deferred tax assets for the years ended December 31, 2014 and 2013 are as follows:

 

   2014   2013 
Deferred tax assets        
Current:        
Accrued payroll  $195,329   $- 
Current   195,329    - 
           
Non-current:          
Net operating loss carry forwards (NOLs)   6,367,071    1,264,000 
Fixed assets   (244,255)   - 
Oil & gas properties   (335,417)   - 
Other   (1,153)   - 
Non-current   5,786,246    1,264,000 
           
Total deferred tax assets   5,981,574    1,264,000 
Less: valuation allowance   (5,981,574)   (1,264,000)
Net deferred tax asset  $-   $- 

 

To date, the Company has generated operating losses. As a result the Company has recorded a full valuation allowance against its net deferred tax assets as of December 31, 2014 and 2013. The change in the valuation allowance for the years ended December 31, 2014 and 2013 was an increase of $4,717,574 and a decrease of $733,000, respectively.

 

Under FASB ASC 740, tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities.  The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement.  Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards. As of December 31, 2014 and 2013, the Company has no liabilities for unrecognized tax benefits.

 

The Company’s policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense.  For the years ended December 31, 2014, and 2013, the Company did not recognize any interest or penalties in its consolidated statement of operations, nor did it have any interest or penalties accrued in its consolidated balance sheet at December 31, 2014 and 2013 relating to unrecognized tax benefits.

 

The tax years 2014, 2013, 2012, 2011, 2010 and 2009 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company is subject.

 

No interest or penalties on unpaid tax were recorded during the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014 and 2013, no liability for unrecognized tax benefits was required to be reported. The Company does not expect any significant changes in its unrecognized tax benefits in the next year.

 

F-34
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

Note 13 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, 2013 the report by LaRoche Petroleum Consultants (“LaRoche”) covered 100% of the Company’s proved oil reserves. For the year ended December 31, 2014 the report by Pinnacle Energy Services (“Pinnacle”) 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 tables summarize the Company’s proved developed and undeveloped reserves (all oil) within the United States, net of royalties, as of December 31, 2014 and 2013:

 

   2014   2013 
Net Proved Reserves  Oil (Bbls)   Gas (Mcf)   Oil (Bbls)   Gas (Mcf) 
Proved Developed Producing   178,218    26,349    20,952    16,995 
Proved Non-producing   530,814    246,113    -    - 
Proved Undeveloped   1,477,331    698,139    2,417    2,099 
Total Proved   2,186,364    970,601    23,369    19,094 

 

   2014   2013 
Net Proved Developed and Undeveloped Reserves  Oil (Bbls)   Gas (Mcf)   Oil (Bbls)   Gas (Mcf) 
Total Net Proved Reserves at January 1   20,952    16,995    26,583    23,669 
Extensions and discoveries   2,470    2,763    1,291    1,149 
Dispositions   (1,419)   (11,766)   -    - 
Acquisitions   2,122,785    959,436    -    - 
Net Production   (13,594)   (1,043)   (9,453)   (561)
Revisions to Previous estimates   55,170    4,216    2,531    (7,262)
Total Net Proved Reserves at December 31   2,186,364    970,601    20,952    16,995 

 

F-35
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

The following tables set forth the aggregate capitalized costs related to oil and natural gas producing activities at December 31, 2014 and 2013.

 

Capitalized Costs Related to Oil and Gas Assets  2014   2013 
Proved Properties  $13,185,888   $3,225,769 
Unproved Properties   12,087,982    1,520,870 
Total   25,273,870    4,746,639 
Less: amount impaired   (3,697,924)   (2,268,977)
Capitalized cost, net of impairment   21,575,946    2,477,662 
Less: accumulated depletion   (790,011)   (707,143)
Capitalized Cost, net of Impairment and depletion  $20,785,935   $1,770,519 

 

Costs incurred in Oil and Gas Activities  2014   2013 
Acquisition of Properties        
Proved  $11,729,417   $- 
Unproved  $11,635,470   $- 
Development  $3,583,931   $734,642 
Exploration  $10,740   $- 

 

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-36
 

 

Stratex Oil & Gas Holdings, Inc.

Notes to Consolidated Financial Statements

December 31, 2014

 

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”:

 

Standardized Measure of Discounted Future Net Cash Flows  2014   2013 
Future Cash Inflows  $182,758,994   $1,865,657.0 
Future Production Costs   (85,240,886)   (849,221)
Future Development Costs   (18,789,601)   - 
Future Asset Retirement Costs   -    (39,138)
Future Income Tax Expenses   -    - 
Future Net Cash Flows   78,728,507    977,298 
10% Annual Discount for Estimated Timing of Cash Flows   (47,271,167)   (216,870)
Standardized Measure of Discounted Future Net Cash Flows  $31,457,340   $760,428 

 

Reconciliation of future cash flows relating to proved reserves  2014   2013 
Undiscounted values as of January 1  $977,298   $1,424,445 
Extensions and discoveries   156,628    198,960 
Dispositions   (159,477)   - 
Acquisitions   76,405,994    - 
Production   (860,190)   (847,257)
Revisions of prior volume estimates   2,332,631    201,150 
Revisions of pricing   (124,377)   - 
Undiscounted values as of December 31   78,728,507    977,298 
10% discount factor   (47,271,167)   (216,870)
Standardized measure  $31,457,340   $760,428 

 

Note 14 Subsequent Events:

 

The Company has evaluated all events that occurred after the balance sheet date through the date when the consolidated financial statements were issued to determine if they must be reported. The management of the Company determined that there were certain reportable subsequent events to be disclosed as follows:

 

On January 15, 2015, and effective as of January 1, 2015, the Company entered into Amended Employment Agreements with the following Executive Officers: Alan D.Gaines, Executive Chairman of the Board; Stephen P. Funk, Chief Executive Officer: Matthew S. Cohen, Executive Vice President and General Counsel; Michael J. Thurz, Chief Administrative Officer; and Michael A. Cederstrom, Vice President. The purpose of the Amended Employment Agreements was to assist with the Company’s cash flow during this period of reduced oil and gas commodity pricing. The amendments to the Employment Agreements removed the provision stating the amount of salary to be paid and replaced it with the following statement, “…salary at the rate to be determined by the Board of Directors. Executive’s base salary may be reviewed and further adjusted from time to time by the Board in its discretion”. Pursuant to this amendment the Board of Directors reduced the Executive Officers base salary by 75%.

 

On February13, 2015, the Board of Directors of the Company, accepted the resignation of Matthew S. Cohen, as the Executive Vice President & General Counsel. Mr. Cohen resigned in order to pursue other business opportunities.

 

On March 13, 2015 the Company entered into a Joint Development Agreement with Itasca Energy LLC (“IE”) whereby IE will drill up to 6 wells in the Buda Limestone formation of the leasehold to earn a 77.5 % working interest in each of the 6 wells which are completed, the Company will retain a 21.3% working interest in each well. IE will pay all cost of development through the tanks on the six wells. If IE completes all six wells they will earn a 77.5 % working interest in 10,314 gross (7,994 net) working interest in the Matthews Lease and 50% working interest in 9,333 gross and (4,666 net) in the remaining portion of the Matthews Lease. The first well of this agreement was spudded on March 16, 2015 each of the 5 remaining wells must be spudded within 120 days of the prior well reaching total depth. If the wells are not spudded with the required time period then IE will earn its interest in the actual wells drilled only and will not earn an interest in the total lease.

 

Effective March 31, 2015 the Company settled litigation against Eagleford Energy, Zavala Inc. The action was for foreclosure of the payment of obligations owed by Eagleford Energy, Zavala Inc. for lease obligations. Prior to foreclosure Eagleford paid the obligations which were owed. On March 31, 2015 this matter was settled by Stratex releasing its interest in the project for the development of the 2,926 acres in Zavala County, Texas, to its two partners Eagleford Energy, Zavala Inc. and Quadrant Energy, Inc. The parties entered into a mutual release of all obligations. Pursuant to the Mutual Settlement Agreement the Company agreed to pay $25,000 in cash and issue 1,333,333 shares of common stock to Eagleford Energy Corp.

 

On March 31, 2015 the Company issued 2,500,000 shares of common stock to one officer, three employees and two consultants of the Company for work that was performed.

 

F-37
 

 

EXHIBIT INDEX

 

Exhibit No.   Description
3.1   Amended and Restated Articles of Incorporation (Incorporated by reference to the Quarterly Report on Form 10-Q filed May 15, 2013)
     
4.1   Form of Promissory Note of Stratex Oil & Gas Holdings, Inc.
     
10.1   Consulting Agreement between Stratex Oil & Gas Holdings, Inc. and Alan Gaines dated October 15, 2013 (Incorporated by reference to the Current Report on Form 8-K filed October 18, 2013)
     
10.2   Purchase, Participation and Operations Agreement between Stratex Oil & Gas, Inc. and Mesa Resources, Inc. dated November 22, 2013 (Incorporated by reference to Current Report on Form 8-K filed December, 2013)
     
10.3   Joint Development Agreement between Eagleford Energy, Inc. Eaglefood Energy, Zavala Inc. and Stratex Oil & Gas Holdings, Inc. dated December 3, 2013 (Incorporated by reference to the Current Report on Form 8-K filed December 10, 2013)
     
10.4   Amendment No. 1 to Executive Employment Agreement
     
10.5   Amendment to Consulting Agreement
     
10.6   Amendment to Executive Employment Agreements (Incorporated by reference to Current Report on Form 8K filed January 22, 2015)
     
10.7   Departure of Officer (Incorporated by reference to Current Report on Form 8K filed February 17, 2015)
     
23.1   Consent of Pinnacle Energy Services L.L.C. dated April 13, 2015 (Filed herewith)
     
31.1   Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith)
     
31.2   Certification of Chief Administrative Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith)
     
32.1   Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith)
     
32.2   Certification of Chief Administrative Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith)
     
99.1   Stratex Oil & Gas Holdings, Inc., Press Release, issued December 3, 2013 (Incorporated by reference to Current Report on Form 8-K filed December 3, 2013)
     
99.2   Stratex Oil & Gas Holdings, Inc., Press Release, issued December 10, 2013 (Incorporated by reference to Current Report on Form 8-K filed December 10, 2013)
     
99.3   LaRoche Petroleum Consultants, Ltd. Engineering Report as of December 31, 2013
     
99.4   Pinnacle Energy Services, LLC Engineering Report as of December 31, 2014 dated March 24, 2015 (Filed herewith)