RICHFIELD OIL & GAS (ROIL) 10-K 2013 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2013

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

For the transition period from to

Commission File Number 000-54576

RICHFIELD OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

Nevada	35-2407100
(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, $0.001 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¨ Nox

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¨ Nox

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.

Yesx 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 x    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 Companyx

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

Yes¨ Nox

The issuer had 52,059,975shares of common stock outstanding as of March 31, 2014. The aggregate market value of the common stock held by non-affiliates, was approximately $19,523,643 based upon the reported sales price of $0.58 which was the average price of the last business day of the previous second quarter on the OTCQX U.S. Premier. 

Richfield Oil & Gas Company

Table of Contents

		Page
Forward-Looking Statements		2
Glossary of Terms		3
Part I
Item 1.	Business	5
Item 1A.	Risk Factors	26
Item 1B.	Unresolved Staff Comments	39
Item 2.	Properties	39
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	40
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	40
Item 6.	Selected Financial Data	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	50
Item 8.	Financial Statements and Supplementary Data	50
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	50
Item 9A.	Controls and Procedures	50
Item 9B.	Other Information	52
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	52
Item 11.	Executive Compensation	55
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
Item 13.	Certain Relationships and Related Transactions, and Director Independence	60
Item 14.	Principal Accountant Fees and Services	64
Part IV
Item 15.	Exhibits and Financial Statement Schedules	65

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 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.

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 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.

“Bbl” means barrel or barrels.

“BOE” means barrels of crude oil equivalent.

“Boepd” means barrels of crude oil equivalent per day.

“Bopd” means barrels of crude oil per day.

“Condensates” are 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.

“MMcf” means 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 Richfield’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 Richfield’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.

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

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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.

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PART I

ITEM 1. BUSINESS

Richfield Oil & Gas Company (“Richfield,” “we,” “us” or “our”) was incorporated in Nevada on April 8, 2011. We are an independent oil and gas exploration and production company with projects in Kansas, Utah and Wyoming. The focus of our business is acquiring, retrofitting and operating or selling oil and gas assets and related production.

Our History

Our Predecessor

Our predecessor company, Hewitt Petroleum, Inc., a Delaware corporation, was incorporated on May 18, 2008. On January 1, 2009, Hewitt Petroleum entered into a Purchase and Sale Agreement with Hewitt Energy Group, LLC for the acquisition of certain subsidiaries, other assets and liabilities including Hewitt Energy Group, Inc., a Texas corporation, and its subsidiary Hewitt Operating, Inc., a Utah corporation, certain oil and natural gas leases, well equipment, and certain liabilities (the “Subsidiary Acquisition”). At the time of the Subsidiary Acquisition, Hewitt Energy Group, LLC was owned and controlled by Douglas C. Hewitt, Sr., our Executive Chairman, President and Chief Executive Officer.

On March 4, 2011, Hewitt Petroleum entered into a Stock Exchange Agreement effective March 31, 2011 with Freedom Oil & Gas, Inc., a Nevada corporation (“Freedom”), which called for the exchange of stock in Hewitt Petroleum for all of the outstanding stock of Freedom (the “Freedom Acquisition”). As a result of the Freedom Acquisition, Freedom became a wholly owned subsidiary of Hewitt Petroleum. The Freedom Acquisition allowed for the consolidation of working interests held by Hewitt Petroleum and Freedom in several Utah exploration projects, as well as the acquisition by Hewitt Petroleum of the remaining assets and liabilities of Freedom.

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.

Transactions Relating to Our Formation

Contemporaneously with our incorporation, we merged with our predecessor company, Hewitt Petroleum (the “Hewitt Petroleum Merger”). In connection with the Hewitt Petroleum Merger, Hewitt Petroleum was merged out of existence and we assumed all of the assets and liabilities of Hewitt Petroleum. The Hewitt Petroleum Merger was approved by our Board of Directors and a majority of the stockholders of Hewitt Petroleum as required by Delaware law.

Following the Hewitt Petroleum Merger, Freedom was a wholly-owned subsidiary of Richfield until June 20, 2011. On June 20, 2011, Freedom was merged with and into Richfield (the “Freedom Merger”). In connection with the Freedom Merger, Freedom was merged out of existence and we assumed all of the assets and liabilities of Freedom.

Our Business Strategy

We have three primary strategic directions:

· 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 2,106 gross (2,011 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 three properties on the Utah–Wyoming Overthrust, including one property containing a well that we are in the process of refurbishing in order to place it into production. We currently own or lease 2,311 gross (1,971 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.

· We have conducted a limited amount of exploration for oil and natural gas reserves in the Central Utah Overthrust region, where we are participating in 33,270 gross (12,530 net) acres.  We refer to these properties as our “Central Utah Overthrust Project.” We and our partners intend to conduct drilling operations, acquire additional acreage and to conduct further exploration activities with respect to our Central Utah Overthrust Project.

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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 areas of operation. The database contains extensive well records, including information on historic production, seismic data, 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.

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.

Properties

We maintain our headquarters at 175 South Main Street, Suite 900, Salt Lake City, Utah 84111 and have temporary operational facilities in Russell County, Kansas and Juab County, Utah. The Kansas facilities include a storage yard for equipment and our Utah facilities are currently located on the current HPI Liberty #1 Well site in Juab County, Utah.

We have been involved in leasing, exploring and drilling activities in Kansas, Oklahoma, Utah and Wyoming since our formation. We are currently participating in 37,686 gross 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, 2014, we had 41 total wells, including 13 producing wells, 17 shut-in wells, eight active saltwater disposal wells and three wells that are currently in the process of completion. As set forth in our Reserves and Engineering Evaluation, dated April 4, 2014, and effective as of December 31, 2013 (the “2013 Pinnacle Reserve Report”), prepared by Pinnacle Energy Services L.L.C. (“Pinnacle”), as of December 31, 2013 we had 13 producing wells, 17 shut-in wells, eight active saltwater disposal wells and three wells that we were in the process of completing. For additional information, please see the 2013 Pinnacle Reserve Report which is filed herewith as Exhibit 99.7.

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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, 2014, we had five fields in our Mid-Continent Project, which contain 38 total wells, including 13 producing wells, one well in the completion stage of development, 16 shut-in wells, and eight saltwater disposal wells. We own a 100% working interest in three of our fields in Kansas, the Gorham Field, the South Haven Field and the Trapp Field. As of March 31, 2014, these three fields collectively contained 27 wells, including 9 producing wells, one well in the completion stage of development, 12 shut-in wells, and five saltwater disposal wells. We have two other Kansas fields, which include the Perth Field, in which we own an 85% working interest and which contains four total wells, including two producing wells, one shut-in well, and one saltwater disposal well, and 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. 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 2,106 gross (2,011 net) acres.

Utah-Wyoming Overthrust Project

We have one field and two prospects in the Utah-Wyoming Overthrust Project, the Graham Reservoir Field, 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 Graham Reservoir Field, located in Uinta County, Wyoming, incorporates 640 acres and contains one well in the completion stage of development, in which we own a 20% 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 2,311 gross (1,971 net) acres. 

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 shut-in well and one well in the completion stage of development. We are the operator of each of these prospects, through our subsidiary Hewitt Operating, Inc. The Liberty Prospect incorporates approximately 447 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, and it is currently in the completion stage of development. We own a 54.8% working interest BPO and a 41.1% working interest APO in the HPI Liberty #1 Well. The HUOP Freedom Trend Prospect incorporates approximately 11,316 acres, in which we own 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 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 Well.” The Pine Springs Prospect incorporates 561 acres, in which we own a 100% working interest BPO and APO. The Edwin Prospect incorporates 946 acres, in which we own a 100% working interest BPO and APO. Our total acreage position in the Central Utah Overthrust Project is 33,270 gross (12,530 net) acres.

Business Opportunity

Our development plan is designed to generate production increases in the initial phase of the development of our projects. We intend to continue to develop the fields in our Mid-Continent Project, where the reserves are proven and drilling costs are modest. For example, all drilling objectives in our Mid-Continent Project are shallow in nature, with depths ranging from 3,100 to 4,300 feet, and are supported by geological and engineering studies. In contrast, our Central Utah Overthrust Project entails greater exploration risk. The HUOP Freedom Trend Prospect will likely require drilling down to depths in the 6,000 to 15,000 feet range, the Liberty Prospect will likely require drilling in the 3,000 to 12,000 feet range and the Independence Prospect will likely require drilling in the 8,000 to 15,000 feet range. We believe that the wells in our Central Utah Overthrust Project, while expensive and risky, have the greatest potential return of any projects in our inventory. With the information gained from drilling and completing the HPI Liberty #1 Well and the shut-in Moroni #1-AXZH Well, we believe that we will be able to better define our drilling objectives within our Utah prospects. We also expect to develop the Graham Reservoir Field, which is in our Utah-Wyoming Overthrust Project, where the reserves are proven and drilling costs are lower than the Central Utah Overthrust Project because of the nature of the geology.

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Project Methodology

Each of the fields we have acquired in the Mid-Continent Project contains old wells that previously produced only a few barrels of oil per day or were shut-in. However, when these wells were originally developed, they had initial production rates of 200 to over 4,000 barrels of oil per day, an indication of superior reservoir permeability. Reservoirs with these characteristics are typically good candidates for hydrostatic reduction/hydrocarbon expansion methodologies, which are often used to obtain higher production rates. These methodologies aim to increase oil production by reducing hydrostatic pressure. Hydrostatic pressure is reduced by pumping fluid out of a well at very high rates. The decrease in hydrostatic pressure allows oil and associated natural gas that were trapped by water to enter the well in greater proportions. We refer to the proportion of oil to water contained in extracted fluid as the “oil cut.” With continued production, the oil cut increases as the amount of water contained in extracted fluid decreases. We plan to equip many of our Kansas wells with submersible pumps and saltwater disposal systems. These pumps are expected to allow for a high rate of fluid extraction, and therefore higher oil and natural gas production. The submersible pumps should also allow the water pressure in the reservoir to be reduced at a significantly increased rate than is possible using traditional pumps.

Corporate Structure

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

Hewitt Energy Group, Inc., a Texas corporation was formed in 1989 and is licensed and bonded as a Kansas operator. Hewitt Operating, Inc., a Utah corporation, was formed in 2005 and is licensed and bonded as a Utah operator and as a Wyoming operator. Both Hewitt Energy Group, Inc. and its subsidiary Hewitt Operating, Inc. were acquired by Hewitt Petroleum, Inc. from Hewitt Energy Group, LLC effective on January 1, 2009. On July 27, 2012, Richfield formed a new 100% owned subsidiary, HR Land Group, LLC, a Utah limited liability company.  HR Land Group, LLC was organized to acquire oil and natural gas leases in Utah. 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 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.

General Development of the Business

During the last three fiscal years, we have raised capital through private placements of equity and debt financings. During the periods ended December 31, 2013, 2012, and 2011, we raised $1,076,378, $3,652,913 and $1,108,744 in cash from the private placement of common stock and common stock warrants; $0, $285,000 and $0 in cash from the private placement of preferred stock; and $1,921,811, $865,595 and $739,984 in cash from debt financings, respectively.

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During the periods ended December 31, 2013, 2012 and 2011, we acquired oil and natural gas properties, including wells and related equipment, for consideration totaling $2,689,922, $7,942,276 and $9,064,387, respectively. Included in these numbers is one significant acquisition, on March 31, 2011, we acquired additional oil and natural gas properties from Freedom valued at $6,904,067 in exchange for common stock and assumption of debt.

We have seven full-time employees and four consultants providing us services, and we expect to increase the number of our employees in 2014 as field operations expand. 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

We are currently developing seven of our thirteen properties. 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:

 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 two of the wells with submersible pumps and the third is on a pumping unit. We have recently deepened and reconfigured the AJ Dowis #1 Well into a saltwater disposal well. The AJ Dowis #1 Well was originally drilled in 1945. We own an 85% working interest in the Perth Field, which incorporates 480 acres. As of March 31, 2014, the Perth Field contained two producing wells, one saltwater disposal well and one well that is shut in. Our development plan contained in the 2013 Pinnacle Reserve Report includes drilling six new wells for production from the Wilcox Formation and two horizontal wells for production from the Mississippian Limestone, another zone we have previously identified. We also anticipate the need for drilling two new saltwater disposal wells in the future.

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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 167 acres.

We have drilled and completed one new well, the RFO Helsel #3-1, in the South Haven Field. This well was put into production in September 2013; currently this well is shut in awaiting a submersible pump change. 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, 2014, the South Haven Field contained one producing well, one saltwater disposal well and one shut in well. Our development plan calls for drilling three new wells 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 160 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 June 2012, we put the RFO Prescott #25-6 Well into production, which is currently shut-in, and in October 2013, we installed a submersible pump in the Prescott #2 Well. As of March 31, 2014, 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 five new wells for production from the Arbuckle Formation; ii) drilling two new horizontal wells for production from the Mississippian Limestone; iii) reconfiguring two existing shut-in wells for production; and iv) drilling an additional saltwater disposal well.

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.

Gorham Field

The Gorham Field is located in Russell County, Kansas. We currently have a 100% working interest in a total of 1,139 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. Our research indicates that this field has a strong water drive compatible with our production methods and has the potential to produce more oil than has previously been produced. Other formations with potential for future production include the Lansing/Kansas City, Tarkio, Topeka, Lower Arbuckle, Gorham Sand and the weathered granite basement rocks. As of March 31, 2014, the Gorham Field contained seven producing wells, nine shut-in wells, three active saltwater disposal wells, and one well we are currently in the completion stage of development. Our development plan includes reworking the nine shut-in wells and drilling 24 new wells for production from the Arbuckle Formation and Gorham Sand and five additional salt water disposal wells.

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Trapp Field

The Trapp Field is located in Russell and Barton Counties in 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. This oil has been obtained almost exclusively from the upper two to 15 feet of the Arbuckle formation. Our research indicates that this field has a strong water drive which is compatible with our production methodology. As a result of our water extraction capabilities, we have the potential to produce additional oil and add reserves relating to the Trapp Field. We believe that substantially more productive intervals exist within the Arbuckle zone, that have not been categorized as PUDs.

The Hoffman lease is located in a portion of the Trapp Field. We own a 100% working interest in the Hoffman lease. This field consists of 160 acres with respect to which we lease 100% of the mineral rights. As of March 31, 2014, the Trapp Field contained four wells, including one producing well, two shut-in wells, and one saltwater disposal well. Our development plan includes reworking the two shut-in wells, 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 field and one prospect in Wyoming and one prospect in Utah, which are described below:

Graham Reservoir Field

The Graham Reservoir Field in Uinta County, Wyoming, consists of 640 acres, in which we own a 48.80% working interest, with the exception of the Wasatch National Forest #16-15 Well in which we own a 28.80% working interest. The Graham Reservoir Field is located on a southern extension of the Moxa Arch. The Graham Reservoir Field is immediately adjacent to four other oil and natural gas fields that are currently producing oil, natural gas and condensate from both the Dakota and Frontier Formations. The Wasatch National Forest #16-15 Well produced oil before being shut-in in 2003. The Wasatch National Forest #16-15 Well is completed in the Dakota Formation at 15,560 feet and has additional untested oil and natural gas potential in the Frontier Formation at 15,160 feet. As of March 31, 2014, the Graham Reservoir Field consisted of one well in the completion stage of development. Our development plan includes flow testing and production operations for the Wasatch National Forest #16-15 Well to put it back into production, a future recompletion of that well in the Frontier Formation and drilling of one new well for production from the Dakota and Frontier Formations. We do not anticipate that sufficient volumes of saltwater will be produced to require a saltwater disposal well.

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 2013 Pinnacle Reserve Report.

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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. 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 2013 Pinnacle Reserve Report.

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 11,316 acres along the Central Utah Overthrust in Sanpete County, Utah, with respect to which we lease 100% of the mineral rights. 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 by us. 

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, Tununk 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 2013 Pinnacle Reserve Report.

Liberty Prospect

The Liberty Prospect is owned by multiple parties. We own a 54.8% working interest BPO and a 41.1% working interest APO in the HPI Liberty #1 Well, and a 65.2% working interest BPO and a 50.1% working interest APO in the remaining Liberty Prospect acreage. The HPI Liberty #1 Well is currently in the completion stage of development.

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The Liberty Prospect incorporates 447 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. 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.

While the HPI Liberty #1 Well was spud 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. Additional completion activities in the HPI Liberty #1 Well are ongoing. Recently, we have evaluated our geological samples and our test results to determine optimal completion methods. Immediate plans to drill other locations in the Liberty Prospect have not yet been determined and no reserves have been assigned to the Liberty Prospect in the 2013 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, 2014, we owned a 3.00% working interest in approximately 20,000 acres in the Independence Prospect, which includes the Moroni #1-AXZH Well. In addition to our 3.00% working interest in 20,000 acres, we own a 44.25% working interest in 11,316 acres of shallow rights in the HUOP Freedom Trend Prospect that largely overlaps with the Tununk shale oil play in the Independence Prospect.

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. It took four months to drill past the Tununk Shale zone and install steel casing in the well. The well was later plugged. While lost circulation is a problem when drilling, it is also an indication that the reservoir has good porosity and permeability. During the four months of drilling in the Tununk Shale, oil flowed to the surface, which is an indication that a significant amount of hydrocarbons are likely present.

In 1996, Cimarron Energy, Inc. re-entered the Moroni #1-AXZH Well and drilled a vertical sidetrack in the well. During drilling, Cimarron measured a gas flare of 20,800 units in the Tununk Shale, in addition to oil flowing to the surface.

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. We plan to participate in the development of the Independence Prospect by funding our 3% working interest requirement when work progresses on the Independence Prospect and no reserves have been assigned to the Independence Prospect in the 2013 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, 2014, we owned a 100.00% working interest in approximately 561 acres in the Pine Springs Prospect. 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 2013 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, 2014, we owned a 100.00% working interest in approximately 946 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. Plans to drill in the Edwin Prospect have not yet been determined and no reserves have been assigned to the Edwin Prospect in the 2013 Pinnacle Reserve Report.

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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. 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, 2013. See “Preparation of Reserves Estimates" on page 16 of this annual report on Form 10-K and the 2013 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, 2013
	Oil (gross)		Oil (net)		Natural Gas (gross)		Natural Gas (net)
Reserves Category	MBbls		MBbls		MMcf		MMcf
PROVED
Developed		620		472		129		103
Undeveloped		1,153		869		559		421
TOTAL PROVED		1,773		1,341		688		524
PROBABLE
Developed		1,361		1,058		600		478
Undeveloped		2,211		1,742		1,072		845
TOTAL PROBABLE		3,572		2,800		1,672		1,323

During 2013, several factors impacted our total Net Proved Undeveloped Reserves:

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· We did not convert any reserves from Net Proved Undeveloped Reserves into Net Proved Developed, because we did not develop any new wells.

· We modified the adjusted economic prices from $2.068/MCF for natural gas and $91.05/Bbl for oil in the Perth and South Haven Fields, $88.45/Bbl for oil in all other Kansas properties, and $84.90/Bbl for oil in the Wyoming properties used in our Reserves and Engineering Evaluation, dated January 18, 2013 (our “2012 Pinnacle Reserve Report”), to $2.75/MCF for natural gas and $93.28/Bbl for oil in the Perth and South Haven Fields, $90.68/Bbl for oil in all other Kansas properties, and $87.13/Bbl for oil in the Wyoming properties used in the 2013 Pinnacle Reserve Report. The pricing revisions caused our Net Proved Undeveloped Reserves to increase by 25 oil MBbls and to increase by 93 natural gas MMcf.

· We increased the lease operating expenses for our development plan to reflect our historical cost levels which resulted in our Net Proved Undeveloped Reserves to decrease by 43 oil MBbls and a decrease by 101 natural gas MMcf.

· We made changes to our two-year development plan, including adding four new drilling locations which increased our Net Proved Undeveloped Reserves by 62 oil MBbls and 30 natural gas MMcf; removing one drilling location from our new two-year development plan which decreased our reserves by 18 oil MBbls and 9 natural gas MMcf; and one drilling location being moved to probable which decreased our reserves by 45 oil MBbls and 0 natural gas MMcf for a total net decrease of 1 oil MBbls and an increase of 21 natural gas MMcf.

· We sold a 60% working interest in the Graham Reservoir Field in Uinta County, Wyoming, which had reserves in place. This sale caused our Net Proved Undeveloped Reserves to decrease by 134 oil MBbls and by 0 natural gas MMcf.

 Estimated Future Income

The future net revenue set forth in our 2013 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		2012		2013		2012
Proved
Proved Developed	$	18,477	$	23,968	$	11,637	$	15,618
Proved Undeveloped		26,917		30,684		17,241		18,308
Total Proved	$	45,394	$	54,652	$	28,878	$	33,926
Probable
Probable Developed	$	67,615	$	76,694	$	41,581	$	50,323
Probable Undeveloped		107,076		122,439		68,856		74,080
Total Probable	$	174,691	$	199,133	$	110,437	$	124,403

The reserve values in the table above are based upon the information found in the 2013 and 2012 Pinnacle Reserve Reports. The values as of December 31, 2013 are based on SEC pricing guidelines, adjusted to reflect estimated differentials, and used fixed oil prices of $93.28/Bbl for the Perth and South Haven Fields, $90.68/Bbl for all other Kansas properties, and $87.13/Bbl for the Wyoming properties, and used a fixed natural gas price of $2.75/MCF for all properties. The values as of December 31, 2012 are based on SEC pricing guidelines, adjusted to reflect estimated differentials, and used fixed oil prices of $91.05/Bbl for the Perth and South Haven Fields, $88.45/Bbl for all other Kansas properties, and $84.90/Bbl for the Wyoming properties, and used a fixed natural gas price of $2.068/MCF for all properties.

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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, 2013. 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.

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, 2013 through December 31, 2013, the unweighted arithmetic average of the first-day-of-the-month price was $3.67/MCF for natural gas and $96.94/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 resulting in an adjusted price of $2.75/MCF for natural gas and $93.28/Bbl for oil in the Perth and South Haven Fields, $90.68/Bbl for oil in all other Kansas properties, and $87.13/Bbl for oil in the Wyoming properties.

For the evaluated Perth and South Haven Fields there was a NYMEX (Cushing) oil differential of ($3.66)/Bbl. For all other Kansas properties there was a NYMEX (Cushing) oil differential of ($10.16)/Bbl offset by a $3.90/Bbl above posted NCRA Kansas Common pricing resulting in a net oil price differential of ($6.26)/Bbl. For the Wyoming properties there was a NYMEX (Cushing) oil differential of ($9.81)/Bbl. For natural gas, prices are projected to be 75% of the NYMEX natural gas price resulting in a ($0.92)/MCF differential, based on prevailing area contracts.

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 Kansas, which is a reasonable and common assumption for the activities of 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 and were estimated to be $3.00 per barrel for the Kansas and Wyoming properties.

Preparation of Reserves Estimates

The 2013 Pinnacle Reserve Report relates to our oil and gas properties as of December 31, 2013. The 2013 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.

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 Chief Executive Officer, Douglas C. Hewitt, Sr., as well as our Independent Engineering Consultant, William A. Alexander. Operating expenses and AFEs are prepared by our operations department, and are reviewed by our Geologist, our Chief Executive Officer, and our Independent Engineering Consultant. 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 2013 Pinnacle Reserve Report. 

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Mr. Burton has sixteen years of experience in oil and gas exploration and production. Mr. Burton has held his position as our Geologist since our inception. Prior to joining Richfield, Mr. Burton held various positions in exploration geology, development planning, operations management, and environmental permitting with Flying J Oil and Gas Inc. and The Shipley Group, LLC. 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 for over thirteen years.

William A. "Bill" Alexander Jr., our Independent Engineering Consultant has in excess of 50 years of experience in petroleum engineering, geology and operations. Mr. Alexander has gained experience by roughnecking, participating in seismic data acquisition, surveying, engineering and geologic data gathering and analysis. Mr. Alexander obtained a degree in mining engineering (petroleum option) from the University of Wisconsin in 1960. He has worked with Shell Oil Co. and Kirby Exploration, and has worked as a consultant in the oil and gas industry since 1974. He has worked in many of the oil and gas fields in the U.S., as well as the Middle East, North Sea and Columbia.

The geological and production data prepared by our Geologist and operations department was provided to Pinnacle for use in generating the 2013 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 Chief Executive Officer, along with our Independent Engineering Consultant and internal Geologist, conducted a final review of the 2013 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.

Evaluation of Reserves

The reserves and values included in the 2013 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 2013 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, 2011, 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, 2012, we did not drill any dry exploratory or dry development wells or any productive exploratory wells. We drilled two gross productive development wells (1.69 net wells).

During the year ended December 31, 2013, we did not drill any dry exploratory or dry development wells or any productive exploratory wells. We drilled one gross productive development well (1.00 net well), one gross salt water disposal well (1.00 net well) and recompleted six gross production wells (4.91 net wells) and one gross salt water disposal well (0.85 net well).

Present Activities

We are not currently drilling any wells. Our current activities consist of recompleting one gross exploratory well (0.55 net well) and two gross development wells (1.20 net wells).

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Oil and Gas Properties, Wells, Operations and Acreage

Productive Wells

We started acquiring properties in January 2009. Since that time we 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.

The following table summarizes, as of March 31, 2014, our producing, shut-in, saltwater disposal wells and wells currently in the drilling or completion stage of development in Kansas, Oklahoma, Utah and Wyoming.

Producing

Shut-In

SWD

Drill/Comp

Gross(1)

Net(2)

Gross(1)

Net(2)

Gross(1)

Net(2)

Gross(1)

Net(2)

Wells

13.00

12.39

17.00

15.54

8.00

7.66

3.00

1.75

(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, 2014, we owned leases in Kansas, Utah and Wyoming. Information about the number of acres for our leases is shown below:

	Undeveloped				Developed				Total
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
Mid-Continent Project		-		-		2,106		2,011		2,106		2,011
Utah-Wyoming Overthrust Project		1,670		1,670		640		301		2,310		1,971
Central Utah Overthrust Project		33,270		12,530		-		-		33,270		12,530
Total		34,940		14,200		2,746		2,311		37,686		16,512

(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.

 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, 2014, 2015 and 2016 are set forth below:

	Acreage Expirations
Years Ended December 31,	Gross		Net
2014		5,820		5,192
2015		2,903		2,354
2016		80		72
Total		8,803		7,618

Our Production History and Costs of Production

The following table presents information about our produced oil volumes during the year ended December 31, 2013 compared to the years ended December 31, 2012 and 2011. We did not produce natural gas during the years ended December 31, 2013, 2012 or 2011. As of December 31, 2013, we were selling oil from a total of 13 gross wells (approximately 12.3 net wells). All data presented below is derived from accrued revenue and production volumes for the relevant period indicated. 

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	Years Ended December 31,
	2013		2012		2011
Net Production:
Oil (Bbl)		11,331		10,931		7,161
Natural Gas (MCF)		-		-		-
Barrel of Oil Equivalent (Boe)		11,331		10,931		7,161
Average Sales Price:
Oil (per Bbl)	$	92.34	$	87.14	$	99.51
Average Production Costs:
Oil (per Bbl)	$	79.44	$	69.93	$	143.04

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 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.

Failure to comply with applicable laws and regulations can result in substantial penalties, and the regulatory burden on the industry in the U.S. 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 review, 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.

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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.

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.

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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.

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.

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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.

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.

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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.

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.

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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 and Wyoming 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.

In addition, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with results to be available by 2014. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. In addition, the U.S. Department of Energy has conducted an investigation of practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods and the U.S. Government Accountability Office has investigated how hydraulic fracturing might adversely affect water resources. Additionally, certain members of Congress have called upon the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

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.

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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 report on our financial statements for the years ended December 31, 2013 and 2012 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.

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 $6,799,584 in 2013 and $7,993,196 in 2012. 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.

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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 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.

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.

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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.

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.

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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.

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 and Wyoming 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 implementation of 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.

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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, 2014, 2015 and 2016 are set forth below:

	Acreage Expirations
Years Ended December 31,	Gross		Net
2014		5,820		5,192
2015		2,903		2,354
2016		80		72
Total		8,803		7,618

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.

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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.

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 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.

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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, 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.

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.

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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.

Reserve estimates arebased 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.

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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 to 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 levelsand 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 2013 Pinnacle Reserve Report, and such variations could be material. The 2013 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 2013 Pinnacle Reserve Report will be reduced to the extent that such activities do not achieve the level of success assumed in the 2013 Pinnacle Reserve Report.

The 2013 Pinnacle Reserve Report sets forth estimates of our reserves as of December 31, 2013 and has not been updated and thus does not reflect changes in our resources since that date.

If our costs of production continue to exceed the estimated costs contained in the 2013 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 2013 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.

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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.

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.

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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 or 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.

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 7.1% of our common stock as of March 31, 2014, Douglas C. Hewitt, Sr., our President and Chief Executive Officer beneficially owned approximately 16.2% of our common stock as ofMarch 31, 2014, Glenn G. MacNeil, a Director and our Chief Financial Officer, owned approximately 4.8% of our common stock as ofMarch 31, 2014and our directors and executive officers collectively beneficially owned approximately 32.8% of our common stock as ofMarch 31, 2014. Consequently, Messrs. Gaines, Hewitt and MacNeil 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 OTCQX U.S. Premier, which may have an unfavorable impact on our stock price and liquidity.

Our common stock is quoted on the OTCQX U.S. Premier (“OTCQX”). The OTCQX is a significantly more limited market than the national securities exchanges. The OTCQX 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.

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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 OTCQX 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 OTCQX, 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.

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.

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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 250,000,000 shares of common stock and 50,000,000 shares of preferred stock. As of March 31, 2014, 52,059,975 common shares and no preferred shares were issued and outstanding. In addition, as of March 31, 2014, we had outstanding warrants to purchase approximately 7,716,587 shares of our common stock, and notes convertible into approximately 15,556,141 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.

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 52,059,975 shares currently outstanding, 33,661,454 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.

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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.

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 February 1, 2012, Nostra Terra Oil & Gas Company (“NTOG”) filed an action against Richfield, Hewitt Petroleum, Inc., Hewitt Energy Group, Inc., and Hewitt Energy Group, LLC in the Twenty-Third Judicial District Court of Russell County, Kansas. The complaint alleges that we defaulted on our repayment obligations under a note and security agreement, dated April 13, 2011, in the principal amount of $1,300,000 and accrued interest at 10% per annum. During 2013 the Company made substantial payments towards the payment of the obligation. On February 14, 2014 the Court entered a final judgment in favor of Nostra Terra Oil and Gas Company and against Richfield Oil & Gas Company and Hewitt Energy Group, Inc. in the sum of $220,849. The Company is in the process of paying the judgment.

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 $50,386 plus interest. The Company believes that this claim was paid in full in September 2011 and plans on vigorously defending the action.

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In February 2014, the Company became aware that on June 6, 2012 United States Fidelity and Guaranty Company filed an action against Douglas C. Hewitt based upon a liability as a guarantor of a plugging bond posted with the Oklahoma Corporation Commission. The Oklahoma Corporation Commission claimed the Bond for plugging a well previously owned by HEGCO Canada and Hewitt Energy Group LLC. Hewitt Petroleum, Inc., the predecessor in interest to Richfield Oil & Gas Company, purchased the assets of Hewitt Energy in January 2009. Pursuant to that purchase, Hewitt Petroleum agreed to indemnify Douglas C. Hewitt. The Bond was guaranteed by HEGCO Canada Inc., which has been discharged in Bankruptcy, Douglas C. Hewitt, J. David Gowdy, Rodney Babb, and Nemaha Services. The Company is seeking contribution towards the judgment from Rodney Babb and Nemaha Services. As of March 17, 2014 the Company has paid $1,500 towards the obligation. The total obligation is $30,754.

At a hearing with the Kansas Corporation Commission (“KCC”) on November 21, 2013, the KCC imposed a $10,000 fine against Hewitt Energy Group, Inc., for the failure to bring certain wells into KCC compliance pursuant to an order issued in August 2012. The Company had brought 16 of 23 wells into KCC compliance as of November 21, 2013. At the November 21, 2013 KCC hearing Hewitt Energy Group, Inc., was provided three weeks per well to finalize the last seven wells to be brought into compliance. In February 2014 Hewitt Energy Group, Inc. was granted an additional three weeks due to local weather conditions. As of March 31, 2014, Hewitt Energy Group Inc. has brought four of the last seven wells into compliance. The remaining three wells are required to be completed by May 23, 2014. If the wells are not in compliance by May 23, 2014, Hewitt Energy Group’s operating license may be suspended until the wells are in compliance and Hewitt Energy Group may be fined. The Company is currently working to bring the last three wells into KCC compliance.

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.

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 and OTCQB under the trading symbol “ROIL” since December 24, 2012 and has been quoted for trading on the OTCQX U.S. Premier since January 29, 2013.

Although our common stock is currently quoted on the OTCQX, 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 OTCQX is a significantly more limited market than the national securities exchanges. The quotation of our common stock on the OTCQX 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.

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As of March 31, 2014, (i) 52,059,975 shares of our common stock were outstanding, (ii) warrants to purchase 7,716,587 shares of our common stock were outstanding, (iii) notes convertible into 15,556,141 shares of our common stock were outstanding, and no shares of our preferred stock were outstanding.

Trading in the Company’s common stock is limited and the prices below should not be viewed as an indication that there is any established public market for the Company’s securities. Prior to January 4, 2013 no shares of our stock were traded.

Quarters Ended	High $		Low $
First Quarter Ending March 31, 2014	$	0.35	$	0.20
Fourth Quarter Ending December 31, 2013	$	0.55	$	0.21
Third Quarter Ending September 30, 2013	$	0.60	$	0.30
Second Quarter Ending June 30, 2013	$	1.04	$	0.46
First Quarter Ending March 31, 2013	$	3.50	$	0.75
Fourth Quarter Ending December 31, 2012		N/A		N/A

As of March 31, 2014, the closing sales price for our common stock on the OTCQX was $0.22.

Restricted Shares

All of our shares of common stock were issued and sold by us in private transactions and are only eligible for public sale if registered pursuant to the Securities Act, or sold in accordance with a valid exemption from registration, such as Rule 144. These shares are “restricted securities” within the meaning of Rule 144 under the Securities Act. As of March 31, 2014, a total of approximately 33,661,454 shares of our common stock can be immediately sold pursuant to Rule 144.

Recent Sales of Unregistered Securities

The following summarizes all sales of our unregistered securities during the three months ended December 31, 2013. 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.

Effective October 23, 2012, we implemented a 1-for-10 reverse stock split of our issued and outstanding common stock. Where applicable, all common share and per common share information described below and in all other sections of this annual report have been retroactively restated to reflect the reverse common stock split.

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

The Company issued 475,106 shares of common stock to unaffiliated debt holders at a price between $0.25 and $0.47 per share for the settlement of notes payable and accrued interest.

The Company issued 272,834 shares of common stock to consultants at a price between $0.25 and $0.40 per share as compensation for services. The shares issued were fully vested.

Warrants Issued During the Three Months Ended December 31, 2013

There were no warrants issued during the three months ended December 31, 2013.

Holders

As of March 31, 2014, we had 637 holders of record of our common stock and no preferred stock outstanding.

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Dividends

We have never paid any dividends or made any distributions on our common stock and we do not intend to pay any dividends or distributions on our common stock in the foreseeable future. If we pay any dividends or distributions in the future, the amount and timing will depend upon a number of factors, including capital requirements, our financial condition and results of operations, tax considerations, statutory and regulatory limitations, general economic conditions and certain restrictions set forth in our bylaws.

In connection with the conversion of the outstanding shares of our preferred stock on December 31, 2012, we paid accrued preferred stock dividends totaling $9,515. The preferred shareholders elected to convert the accrued dividends into a total of 5,947 shares of our common stock based on a conversion price of $1.60 per share. As of December 31, 2012, following the conversion of all of our outstanding preferred stock, no shares of our preferred stock remain outstanding.

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 of our Business

We are an independent oil and gas exploration and production company with projects in Kansas, Utah and Wyoming. The focus of our business is acquiring, retrofitting and operating or selling oil and gas assets and related production. We have three primary strategic directions:

· We use our research technology to identify prospective properties in Kansas 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 2,106 gross (2,011 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 three properties on the Utah–Wyoming Overthrust, including one property containing a well that was placed into production during 2013 but is currently shut-in. We currently own or lease 2,311 gross (1,971 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.

· We have conducted a limited amount of exploration for oil and natural gas reserves in the Central Utah Overthrust region, where we are participating in over 33,270 gross (12,530 net) acres.  We refer to these properties as our “Central Utah Overthrust Project.” We and our partners intend to conduct drilling operations, acquire additional acreage and conduct further exploration activities with respect to our Central Utah Overthrust Project.

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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 areas of operation. The database contains extensive well records, including information on historic production, seismic data, 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.

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.

Production History

The following table presents information about our produced oil volumes during the year ended December 31, 2013 compared to the year ended December 31, 2012. We did not produce natural gas during these time periods. As of December 31, 2013, and December 31, 2012 we were selling oil from a total of 13 gross wells (12.3 net).

	Years Ended December 31,
	2013		2012
Net Production:
Oil (Bbl)		11,331		10,931
Average Sales Price:
Oil (per Bbl)	$	92.34	$	87.14
Average Production Costs:
Oil (per Bbl)	$	79.44	$	69.93

Depletion of Oil and Gas Properties

Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs.  Our depletion expense totaled $132,260 and $110,296 for 2013 and 2012, respectively. The following table presents our depletion expenses per barrel of oil for 2013 and 2012.

	Years Ended December 31,
	2013		2012
Depletion of Oil (per Bbl)	$	11.66	$	10.09

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Results of Operations

The following presents an overview of our results of operations for the year ended December 31, 2013, compared to the year ended December 31, 2012.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Average Daily Production. Our net oil production for 2013 averaged approximately 31 Bopd after royalties compared to approximately 30 Bopd for 2012.

Oil Revenues. Our oil revenues increased by $93,770 or 9.8% from $952,566 for 2012 to $1,046,336 for 2013. The increase in revenue is due to an increase in our average price of $5.20 per barrel or $58,914. Production increased by 400 barrels of oil in 2013 over 2012 accounts for the balance of the increase of $34,856.

Net Loss on Earnings Per Share. We realized a net loss of $6,799,584 (approximately $(0.19) per basic and diluted share of common stock) for 2013 compared to a net loss of $7,993,196 (approximately $(0.28) per basic and diluted share of common stock) for 2012. The decrease in net loss on earnings per share was primarily due to a decrease of $1,889,897 in our operating expenses and an increase in our weighted average shares outstanding for the year in the amount of 7,519,947 shares.

Operating Expenses. Total operating expenses were $6,271,501 for 2013 compared to $8,161,398 for 2012. The $1,889,897 or 23.2% decrease in operating expenses was due primarily to a decrease in general and administrative expenses ($2,811,585) which was offset by a decrease in the gain on sale of assets ($366,286); increases in asset retirement obligations ($161,901); increases in lease expirations ($156,739); increases in production expenses ($135,672); and all other items ($101,090).

Production Expenses. Our production expenses for 2013 were $900,129, or $79.44 per barrel of oil, compared to $764,457, or $69.93 per barrel of oil, for 2012, which represents a $135,672 or 17.7% increase. The overall production expenses increased mainly due to one-time repair costs incurred on our Wasatch National Forest #16-15 Well that were necessary after it was put into production. This increase was partially offset by a large one time repair charge in our Perth field during 2012 that we did not incur in 2013. Our cost per barrel continues to remain above the industry averages due to our fixed costs, such as electricity, personnel and related expenses, and the cost of maintaining our 27 current non-producing wells including eight salt water disposal wells that are underutilized. We expect our fixed costs on a per barrel basis will decline as we place into production our non-producing wells.

Exploration Expenses. Exploration expenses decreased 18.4%, or $30,781, from $167,212 for 2012 to $136,431 for 2013. This decrease is mainly due to less work performed in 2013 on our undeveloped Utah prospects. In 2013, we focused more of our resources on our proved properties, which are primarily in Kansas.

Lease Expirations. Lease expirations were $182,032 for 2013 compared to $25,293 for 2012. The $156,739 increase in lease expirations was attributable mainly to one lease in Kansas that we were unsuccessful in renewing due to excessive terms requested by the mineral owner, as well as a reserve established in 2013 for future leases that will expire in Utah because they are either over current market value for their renewal, do not have a renewal option or we will elect not to renew.

Depletion, Depreciation, Amortization and Accretion. We recorded depletion, depreciation, amortization and accretion of $382,690 during 2013 compared to $261,739 during 2012. The increase of 46.2%, or $120,951 was mainly due to increased depreciation of $95,422 during 2013 on our well and office equipment as a result of $1,223,833 in equipment additions since 2012. Depletion expense increased by $21,964 as a result of an increase in overall production volumes with a shift to more production in the Koelsch and South Haven fields that have a higher depletion cost per barrel. The remaining increase of $3,565 is due to an increase of accretion of the discount on our asset retirement obligation.

General and Administrative Expenses. General and administrative expenses were $4,571,642 for 2013 compared to $7,383,227 for 2012. The $2,811,585 or 38.1% decrease was attributable to: (i) $2,266,693 decrease of employee and director compensation; (ii) $1,483,135 decrease in consulting fees; (iii) a $391,514 increase in legal and audit fees due to our efforts in raising capital, and (iv) a net decrease of $248,280 in all other expense items. The general and administrative expenses include $1,140,601 and $3,609,444 in 2013 and 2012, respectively for non-cash equity compensation.

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Asset Retirement Obligation Expenses. We had $161,601 in asset retirement obligation expenses for 2013 compared to zero in 2012. This increase is due to the cost for plugging three wells in Kansas during 2013 exceeding the asset retirement obligation liability for those three wells. These wells had been shut-in since our purchase of the leases. They were in very poor mechanical condition that was unknown to us prior to starting our rework operations.

Gain on Sale of Assets. During 2013 we had a net gain on sale of assets of $105,106 compared to $471,392 for 2012. The gain on sale of assets in 2013 is primarily attributable to the sale of 71.25% working interest in our Wasatch National Forest #16-15 Well. The gain on sale of assets in 2012 is mainly attributable the sale of 21% working interest in the Prescott Lease and a 5% carried interest in the Perth Field.

Other Income (Expenses). Total other income and expenses during 2013 was a net expense of $1,572,852 compared to a net expense of $783,964 for 2012 representing an increase of $788,888 or 100.6%.

Loss on Extinguishment of Debt. In 2013, we incurred a loss on the extinguishment of debt in the amount of $1,103,702. This is a non-cash expense and is the result of our effort to reduce our debt through conversions to common stock with a ratchet provision and warrants.

Gain on Derivative Valuation.The Company incurred a gain of $756,776 on the derivative valuation of the ratchet provision on certain shares of common stock. This is a non-cash gain determined by the change in the fair value of the provision for the year 2013.

Interest and Finance Expenses.For the year 2013, we incurred interest and finances expenses of $1,257,143 compared to $1,104,612 for the year 2012. The $152,531 increase in 2013 over 2012 is due to an increase of $293,054 in expenses mainly due to incentive payments for new debt issued and payments made to extend due dates on notes payable during the year 2013, an increase of $184,477 associated with the modification of previously issued warrants, off set by a decrease of $325,000 in debt issuance fees we incurred in 2012 that did not occur in 2013. The interest and finance expenses include $865,347 and $220,549 in non-cash stock and warrant issuances for the years 2013 and 2012, respectively.

Interest Income.For 2012, the Company had $299,879 of interest income associated with past due receivables from a working interest holder. In 2013, we had $850 in interest income.

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to meet potential cash requirements. 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. In the future, we expect to generate cash from sales of crude oil from production from our existing wells and new wells we intend to develop. Until cash provided by our operations is sufficient to cover our expenses and execute our development plans, we intend to continue to finance our operations through additional debt or equity financings, if available.

The following table summarizes our total current assets, total current liabilities and working capital deficiency as of December 31, 2013 compared to December 31, 2012: 

	December 31,			December 31,
	2013			2012
Current Assets	$	613,822		$	1,064,566
Current Liabilities		8,847,612			5,802,513
Working Capital Deficiency	$	(8,233,790	)	$	(4,737,947	)

Cash and cash equivalents were $60,395 as of December 31, 2013, compared to $286,013 as of December 31, 2012. Changes in the net cash provided by and (used in) our operating, investing and financing activities are set forth in the following table:

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	Year Ended						Net Cash
	December 31,						Increase
	2013			2012			(Decrease)
Net cash used in operating activities	$	(994,034	)	$	(3,526,836	)	$	2,532,802
Net cash provided by (used in) investing activities		(1,011,394	)		66,679			(1,078,073	)
Net cash provided by financing activities		1,779,810			3,709,013			(1,929,203	)
Increase (decrease) in cash and cash equivalents	$	(225,618	)	$	248,856		$	(474,474	)

Net cash from operating activities is derived from net income from operations adjusted for non-cash items, changes in the balances of accounts receivables, deposits and prepaid expenses, accounts payables, accrued expenses and other payables. For the year 2013, we used net cash in operating activities in the amount of $994,034 compared to $3,526,836 for the year 2012. This increase in net cash of $2,532,802 from 2012 to 2013 was primarily due to an increase in accrued expenses and other payables of $2,174,500 with a net increase of $358,302 in all other operating items.

Net cash from investing activities is derived from the proceeds and disbursements from sales and purchases of oil and gas properties, including wells and related equipment. Cash used for investing activities for the year 2013 was $1,011,394 compared to having cash provided by investing activities for 2012 in the amount of $66,679. This decrease in net cash of $1,078,073 between the two years was primarily due to a decrease in the proceeds from sale of oil and gas assets. In 2012 we sold significantly more working interests in our properties to provide funding for our activities.

Net cash from financing activities is derived from the proceeds from the issuance of equity securities and notes and convertible notes payable reduced by payments on our notes and convertible notes payable. For the year ended 2013, we had an increase in net cash from financing activities of $1,779,810 compared to an increase in net cash of $3,709,013 for the year 2012. This decrease of $1,929,203 period over period was due to a decrease of $2,861,535 in cash raised through equity securities in 2013 from 2012, offset by an increase of $1,056,216 in cash raised through the issuance of new debt and an increase in payments on our notes payable, convertible notes payable, and capital leases in the amount of $123,884 for the year 2013 over 2012, respectively.

Satisfaction of our cash obligations for the next 12 months and our ability to continue as a going concern

Our operations do not produce significant cash flow and we rely almost exclusively on external sources of liquidity. We currently have a $8,233,790 working capital deficiency and we need additional funding to pay our current liabilities, continue as a going concern and execute our business plan. We have historically addressed working capital deficiencies through frequent private sales of stock and warrants for cash, exchanges of stock and warrants in satisfaction of liabilities or for services, issuing short- and long-term promissory notes and sales of our assets. We will continue to depend on these and other external sources of liquidity for the foreseeable future. If we cannot obtain the necessary capital to pay our current liabilities, we may be subject to litigation and foreclosure proceedings. We will also need to obtain additional funding to make our planned capital expenditures. If we are unable to secure such additional funding, we will be unable to pursue our plans, and we may have to cease or significantly curtail our operations, including our plans to acquire additional acreage positions and development activities. Our ability to raise additional capital is critical to our ability to continue to operate our business. Failure to obtain the needed financing would result in a material adverse impact upon the Company’s operations.

Our ability to secure liquidity in the form of additional financing or otherwise is crucial for the execution of our plans and our ability to continue as a going concern. 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. 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.

Our independent registered public accounting firm’s report on our 2013 financial statements expresses doubt about our ability to continue as a going concern. The report includes an explanatory paragraph stating 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 through 2014 or later. The financial statements do not include any adjustments relating to the recoverability and classification of recorded assets and classification of liabilities that might be necessary should we be unable to continue as a going concern.

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We are not currently generating significant revenues, and our cash and cash equivalents will continue 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 need to continue to raise additional funds to continue operating as a going concern. We may seek this additional funding through the issuance of debt, preferred stock, equity or a combination of these instruments. We may also seek to obtain financing through the sale of working interests in one or more of our projects. We cannot be certain that funding from any of these sources will be available on reasonable terms or at all. If we are unable to secure adequate funds on a timely basis on terms acceptable to us, we may have to cease or significantly curtail our operations including our plans to acquire additional acreage positions and development activities.

We anticipate generating operating profits over the next twelve months. However, over the next twelve months, we do not expect our existing capital and anticipated funds from operations to be sufficient to sustain our planned expansion. Consequently, we intend to seek additional capital to fund growth and expansion through equity financings, debt financings and/or credit facilities. We have no assurance that such financing will be available, and if available, the terms under which such financing would be given.

Our lack of significant operating history makes predictions of future operating results difficult. Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in an early stage of development, particularly companies in the oil and gas exploration industry. Such risks include, but are not limited to, an evolving and unpredictable business model and the management of growth. To address these risks we must, among other things, implement and successfully execute our business and marketing strategy, continue to develop and upgrade technology and products, respond to competitive developments, and attract, retain and motivate qualified personnel. We have no assurance that we will be successful in addressing such risks, and the failure to do so would have a material adverse effect on our business prospects, financial condition and results of operations.

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. 

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

We have significant obligations to plug and abandon our oil and natural gas wells and related equipment. Liabilities for asset retirement obligations are recorded at fair value in the period incurred. The related asset value is increased by the same amount. Asset retirement costs included in the carrying amount of the related asset are subsequently allocated to expense as part of our depletion calculation.

Estimating future asset retirement obligations requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine the fair value. Present value calculations inherently incorporate numerous assumptions and judgments, which include the ultimate retirement and restoration costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of our existing asset retirement obligation liability, a corresponding adjustment will be made to the carrying cost of the related asset.

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Revenue Recognition

Revenue from the sale of crude oil, natural gas and natural gas liquids is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer, which is usually when legal title passes to the external party. For crude oil and natural gas liquids, delivery generally occurs upon pick up at the field tank battery and natural gas delivery occurs at the pipeline delivery point. Revenue is not recognized for the production in tanks, or oil in pipelines that has not been delivered to the purchaser. Revenue is measured net of discounts and royalties. Royalties and severance taxes are incurred based on the actual price received from the sales. We use the sales method of accounting for natural gas balancing of natural gas production, and we would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. For all periods reported, we had no natural gas production.

 Stock-Based Compensation

We have accounted for stock-based compensation under the provisions of FASB Accounting Standards Codification (ASC) 718. This standard requires us to record an expense associated with the fair value of stock-based compensation. We use the Black-Scholes option valuation model to calculate the value of options and warrants at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.

Stock Issuance

We record the stock-based awards issued to consultants and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable, using the measurement date guidelines enumerated in FASB ASC 505-50.

Income Taxes

We account for income taxes under FASB ASC 740. Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.

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

We account for oil and natural gas properties by the successful efforts method. Under this method of accounting, costs relating to the acquisition of and development of proved areas are capitalized when incurred. 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 costs are 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 natural 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 our wells and related equipment and facilities.

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Depletion of producing oil and natural 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 our 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 natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We compare net capitalized costs of proved oil and natural 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 our 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. We have recorded no impairment on any of our properties.

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.

The sale of a partial interest in a proved oil and natural 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 is accounted for as the sale of an asset, and a gain or loss is recognized. The unamortized cost of the property or group of properties is apportioned to the interest sold and 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.

Oil and Gas Reserves

The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.

The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to our properties included in the prior year’s estimates. These revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in oil and natural gas prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.

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Use of Estimates

The preparation of financial statements under GAAP in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved oil and natural gas reserve volumes, certain depletion factors, future cash flows from oil and natural gas properties, estimates relating to certain oil and natural gas revenues and expenses, valuation of equity-based compensation, valuation of asset retirement obligations, estimates of future oil and natural gas commodity pricing and the valuation of deferred income taxes. Actual results may differ from those 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.

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

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Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chairman and Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), has 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, 2013. Based on this evaluation, the CEO and CFO have concluded that, as of December 31, 2013, our disclosure controls and procedures were 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, 2013, 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.

Our management, under the supervision and with the participation of our CEO and CFO conducted an evaluation of our internal control over financial reporting and concluded that, as of December 31, 2013, such internal control over financial reporting is effective. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) inInternal 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.

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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 two vacancies on our Board of Directors. Pursuant to our bylaws, the Board of Directors may fill these vacancies or, alternatively, may reduce the size of the Board of Directors to eliminate these vacancies. As of the date of this filing, the Board of Directors has not taken any action with respect to these vacancies. 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, 2014 and position of our directors and executive officers:

Name	Age	Position
Alan D. Gaines	58	Executive Chairman
Douglas C. Hewitt, Sr.	55	President and CEO
Glenn G. MacNeil	55	CFO and Director
John J. McFadden	69	Director
Joseph P. Tate	70	Director
Thomas R. Grimm	69	Director
Michael A. Cederstrom	61	General Counsel and Corporate Secretary

Alan D. Gaines became the Executive Chairman of the Board of Directors on May 6, 2013. 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 to 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. (OTCBB: DUNR) 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, he served as Vice-Chairman and from April 2005 until July 18, 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. Mr. Gaines served on the board of directors of Eagleford Energy Inc. (OTCBB: EFRDF) until December 2013. 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. (OTCBB: EFRDF), an independent E&P company with properties located in South Texas.

Douglas C. Hewitt, Sr. was appointed our President and Chief Executive Officer on December 15, 2011. Mr. Hewitt served as President and Chief Executive Officer of Hewitt Petroleum, Inc., our predecessor, from its inception on May 18, 2008 to March 31, 2011 and served as the President of Hewitt Energy Group, LLC from 2000 to 2008. Mr. Hewitt brings to our Board of Directors a depth of understanding of our business and operations, as well as the oil and gas industry. Mr. Hewitt has over 27 years of experience in managing all aspects of oil company development, including geological analysis, design and implementation of advanced engineering, field management and finance. In 1988, Mr. Hewitt founded Hewitt Energy Group, LLC. In 1991, Mr. Hewitt founded Nemaha Services Inc., a field services group with more than 50 employees based in Blackwell, Oklahoma, to facilitate the drilling and field activities of his privately held oil and gas company. In 1995, Mr. Hewitt founded HEGCO Canada Inc., an oil and gas exploration and production company, where he served as Chairman and CEO from 1995 to 2000. Mr. Hewitt left HEGCO Canada, Inc. in 2000 to pursue other business activities, including securing a larger acreage position in the Utah Overthrust Belt. Mr. Hewitt attended Merritt Community College.

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Glenn G. MacNeilhas served as our Chief Financial Officer since April 1, 2011 and as a member of our Board of Directors since that time. Mr. MacNeil brings to our Board of Directors over 30 years of international experience in chief financial officer and director roles in both the oil and gas and financial services industries. Mr. MacNeil is a Canadian Chartered Accountant (CA) and a U.S. Certified Public Accountant of South Carolina (CPA). Mr. MacNeil has been an officer and served as director for numerous private and publicly-held companies, some of which are as follows: President of MacKov Investments Limited, a Canadian investment company, from 2007 to the present; CFO and Executive Vice President of GCAN Insurance Company, a Canadian regulated insurance company, from 2008 to 2011; Finance Director of Nostra Terra Oil and Gas Company, PLC, a U.K. based LSE-AIM listed oil and gas company, from 2007 to 2009; Finance Director of CNA Insurance Company Limited, a European regulated insurance company, from 2004 to 2008; Chief Financial Officer and Executive Vice President of Continental Casualty Company, a Canadian regulated insurance company (also known as “CNA Canada”), from 1998 to 2004; and Vice President Finance, Canadian Operations of Everest Reinsurance Company and Vice President Finance and Director of Everest Insurance Company of Canada, Canadian regulated reinsurance and insurance companies, from 1988 to 1998. Mr. MacNeil has taken leading roles in acquisitions, divestitures, turnaround situations and start-up businesses. In addition to serving on our Board of Directors, Mr. MacNeil serves as a director of HEGCO Canada Inc., a TSX-V listed, non-trading shell company. Mr. MacNeil is a member of the Society of Management Accountants of Ontario (CMA), Ontario Institutes of Chartered Accountants (CA), and Certified Public Accountants of South Carolina (CPA). Mr. MacNeil received a Bachelor of Business Administration degree (BBA) from Cape Breton University, Nova Scotia.

John J. McFaddenhas served on our Board of Directors since May 18, 2008 and serves as the Chairman of the Compensation and Audit Committees. 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. Tatehas served on our Board of Directors since March 31, 2012 and serves as the Chairman of the Nominating and Corporate Governance Committee and as a member of the Audit Committee and the Compensation Committee.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.

 Thomas R. Grimmhas served on our Board of Directors since December 10, 2012 and serves as a member of the Audit Committee and the Nominating and Corporate Governance Committee. Mr. Grimm brings many years of top-level business and entrepreneurial experience to our Board. From 1998 to 2002, Mr. Grimm served as President and CEO of Sam’s Club as well as Executive Vice President of Wal-Mart Stores Inc., based in Bentonville, Arkansas. From 1993 to 1994, Mr. Grimm served as the CEO of Pace Membership Warehouse, a subsidiary of Kmart Stores Inc., based in Denver, Colorado. From 1982 to 1990, Mr. Grimm was the founder, President and CEO of Price Savers Membership Warehouse, based in Salt Lake City, Utah, which achieved one billion dollars in sales in its last year prior to being acquired by Kmart Stores Inc. Mr. Grimm has also worked with companies such as Target Stores, a division of Dayton Hudson; Venture Stores, a division of May Company; and Medi-Mart, a division of Stop N Shop Companies. From 2004 to 2005, Mr. Grimm served as the CEO of Naartjie Custom Kids, a children’s clothing store. Since 2008, Mr. Grimm has been a Partner in RST LLC, which supplies products to the online sales divisions of companies such as Costco, Amazon, Overstock, Home Depot and many others. RST LLC also operates two websites, Flowwall.com and RSToutdoors.com. Mr. Grimm is a graduate of Weber State University.

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Michael A. Cederstrom has served as our General Counsel and Corporate Secretary since December 15, 2011. Mr. Cederstrom provided legal services to us 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 31 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 17 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.

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.

Based solely on a review of the copies of Forms 4 and 5 furnished to us, or written representations from reporting persons that all reportable transactions were reported, we believe that during the fiscal year ended December 31, 2013 all of our executive officers, directors and greater than 10% holders, if any, filed the reports required to be filed under Section 16(a) on a timely basis under Section 16(a).

Code of Ethics

We have adopted a code of ethics, as defined by Item 406(b) of Regulation S-K under the Exchange Act, that applies to our principal executive officer, principal financial officer and principal accounting officer or controller. A copy of the code of ethics is posted on our website, at www.richfieldoilandgas.com. We intend to disclose any amendments to, or waivers from, our code of ethics on our website.

Audit Committee

The audit committee of our Board of Directors is currently comprised of John J. McFadden, Thomas R. Grimm and Joseph P. Tate. Our Board of Directors has determined that each member of the audit committee (1) is “independent” as defined by the applicable SEC rules and NYSE listing rules, (2) has not participated in the preparation of our financial statements or any of our current subsidiaries at any time during the past three years and (3) is able to read and understand fundamental financial statements, including a company’s balance sheet, income statement and cash flow statement. Our Board of Directors has appointed Mr. McFadden as Chairman of the audit committee.

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ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The table below sets forth compensation earned by our named executive officers in 2013 and 2012 for services rendered in all capacities to us and our subsidiaries.

Name and Principal Position		Year		Salary		Bonus		Stock Awards		Option Awards		Non-Equity Incentive Compensation		All Other Compensation		Total
				($)		($)		($)		($)		($)		($)		($)
				(1)				(2)		(3)				(4)
Alan D. Gaines	(5)		2013		192,000		-		-		795,009		-		-		987,009
Executive Chairman of the Board			2012		-		-		-		-		-		-		-
Douglas C. Hewitt, Sr.	(6)		2013		410,000		-		-		-		-		-		410,000
President and Chief Executive Officer			2012		360,000		-		507,500		-		-		50,000		917,500
Glenn G. MacNeil	(7)		2013		-		-		-		-		-		326,000		326,000
Chief Financial Officer and Director			2012		138,000		-		352,500		-		-		188,000		678,500
Michael A. Cederstrom	(8)		2013		266,000		-		-		-		-		-		266,000
General Counsel and Corporate Secretary			2012		216,000		-		322,500		-		-		50,000		588,500

(1)	In 2013, 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, 2013. Mr. Gaines’ annual salary is $288,000 and he earned $192,000 in 2013 all of which has been accrued and unpaid as of December 31, 2013. (ii) Mr. Hewitt earned $410,000 of which $303,661 was paid in cash in 2013 and the remaining $106,339 has been accrued and unpaid as of December 31, 2013 (iii) Mr. Cederstrom earned $266,000 of which $201,242 was paid in cash in 2013 and the remaining $64,758 has been accrued and unpaid as of December 31, 2013. In 2012, base salary compensation was earned by and paid to our named executive officers as follows: (i) Mr. Hewitt earned $360,000, all of which was paid in cash in 2012; (ii) Mr. MacNeil’s services to Richfield were governed by an employment agreement relating to his services while in the United States, under which Mr. MacNeil earned $138,000; and a financial services agreement through MacKov relating to services performed while in Canada, under which MacKov earned $138,000, for an aggregate of $276,000, all of which was paid in cash in 2012; and (iii) Mr. Cederstrom earned $216,000, all of which was paid in cash in 2012.
(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. Mr. Gaines was awarded 3,500,000 options which are exercisable at $1.00 for a period of seven years. The total estimated valuation of Mr. Gaines’ options was $1,590,018 at the time of the award of which $795,009 was vested and expensed during 2013.
(4)	In 2013, “All Other Compensation” earned by our named executive officers included: (i) Mr. MacNeil’s services to Richfield were governed by an employment agreement relating to his services while in the United States, under which Mr. MacNeil earned $0 in 2013; and a financial services agreement through MacKov relating to services performed while in Canada, under which MacKov earned $326,000 in consulting fees of which $68,853 was paid in cash in 2013 and the remaining $257,147  has been accrued and unpaid as of December 31, 2013.   In 2012, “All Other Compensation” earned by our named executive officers included: (i) Mr. Hewitt earned $50,000 all of which was paid in cash in 2012 as director’s fees; (ii) Mr. MacNeil’s $188,000 includes $138,000 earned by MacKov for consulting services and $50,000 which was earned by MacNeil for director’s fees, all of which was paid in cash in 2012; and (iii) Mr. Cederstrom, earned $50,000 all of which was paid in cash in 2012 as corporate secretary fees.

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(5)	Mr. Gaines was appointed Executive Chairman of the Board on May 6, 2013.
(6)	At our inception, Douglas C. Hewitt, Sr. was appointed to serve as Executive Chairman of our Board of Directors and our Chief Operating Officer.  Effective December 15, 2011, Mr. Hewitt resigned as our Chief Operating Officer and was appointed as our President and Chief Executive Officer. On May 6, 2013, Mr. Hewitt resigned as Executive Chairman of our Board of Directors; however he will remain as a director.
(7)	Since our inception on April 8, 2011, Glenn G. MacNeil has served as our Chief Financial Officer and as one of our Directors. During 2011, Mr. MacNeil’s services as Chief Financial Officer were governed by a financial services agreement between Richfield and MacKov.  In 2012, Mr. MacNeil’s services as Chief Financial Officer were governed by an employment agreement relating to his services while in the United States, as well as a financial services agreement through MacKov relating to services performed while in Canada.
(8)	From our inception until December 15, 2011, Mr. Cederstrom provided services to Richfield as a consultant.  Effective December 15, 2011, Mr. Cederstrom was appointed as our General Counsel and Corporate Secretary.

Employment and Consulting Agreements

We have entered into written executive employment agreements with each of our named executive officers, as well as a financial services agreement with MacKov relating to services provided by Glenn G. MacNeil (the “Executive Agreements”), each of which are effective as of January 1, 2012, with the exception of Mr. Alan D. Gaines whose employment agreement was dated May 6, 2013. 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 compensation committee or Board of Directors, and are based on our achievement of specified predetermined and mutually agreed-upon performance objectives each year. Effective January 1, 2013, the previous Board of Director fees of $50,000 per year for Mr. Hewitt and Mr. MacNeil and Mr. Cederstrom’s previous corporate secretary fees of $50,000 per year were added to their annual salary or consulting fees and are no longer compensated separately as director or corporate secretary fees.

We have entered into financial services agreements with MacKov relating to Mr. MacNeil’s services as Chief Financial Officer. In 2012 and 2013, Mr. MacNeil’s services as Chief Financial Officer were governed in part by an employment agreement between Richfield and Mr. MacNeil for services provided while residing in the United States and in part by a financial services agreement, effective January 1, 2012, between Richfield and MacKov for Mr. MacNeil’s services provided while residing in Canada. MacKov is an Ontario, Canada incorporated private company that is wholly owned and controlled by Mr. MacNeil and his spouse.

Prior to January 1, 2012, Douglas C. Hewitt, Sr. had entered into an Employment Agreement with Richfield to act as the Chairman of our Board of Directors and our Chief Operating Officer, which was amended December 31, 2012. Effective January 15, 2014, Mr. Hewitt’s employment agreement was modified to remove the non-compete clause from his contract and replace it with the right to propose projects to the Company and if the Company declines full participation, he can then participate in the project individually.

Alan D. Gaines’ employment agreement dated May 6, 2013 was modified on January 15, 2014 canceling 3,500,000 outstanding stock options and issuing 4,908,532 restricted Company common stock representing 9.9% of the Company’s common shares at the time. The stock was fully vested and the fair value of t $,1,472,560, or $0.30 per share will be expensed in the first quarter of 2014.

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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 Richfield is payable in cash or Richfield stock, at the election of the individual receiving such bonus.

Discretionary Bonuses

In addition to annual incentive bonuses discussed above, the compensation committee of 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.

Perquisites

From January 1, 2012 to December 31, 2012, Douglas C. Hewitt, Sr. had the right to receive up to a 1% overriding royalty interest in new leases acquired by Richfield. Mr. Hewitt received no overriding royalty interests in any new leases acquired by Richfield during this period. Effective December 31, 2012, pursuant to an amendment to Mr. Hewitt’s employment agreement, Mr. Hewitt no longer has the right to receive such overriding royalty interests in the future.

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.

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Compensation Committee Interlocks and Insider Participation

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

Compensation Committee Report

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 Richfield 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 OTCQX, 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)		2013		50,000		-		50,000
Joseph P. Tate	(2)		2013		50,000		-		50,000
Thomas R. Grimm	(3)		2013		50,000		-		50,000
Douglas C. Hewitt, Sr.	(4)		2013		-		-		-
Glenn G. MacNeil	(5)		2013		-		-		-
Alan D. Gaines	(6)		2013		-		-		-

(1) John J. McFadden has served as one of our non-employee directors since May 2008. In 2013, Mr. McFadden earned $50,000 for director’s fees, of which $1,000 was paid in cash and $12,500 was paid in stock, and the remaining $36,500 has been accrued and unpaid as of December 31, 2013.

(2) Joseph P. Tate has served as one of our non-employee directors since March 2012. In 2013, Mr. Tate earned $50,000 for director’s fees, of which $12,500 was paid in stock, and the remaining $37,500 has been accrued and unpaid as of December 31, 2013.

(3) Thomas R. Grimm has served as one of our non-employee directors since December 10, 2012. In 2013, Mr. Grimm earned $50,000 for director’s fees, of which $12,500 was paid in stock, and the remaining $37,500 has been accrued and unpaid as of December 31, 2013.

(4) Douglas C. Hewitt, Sr. has served as Executive Chairman of our Board of Directors since our inception until May 6, 2013. In 2013, Mr. Hewitt did not earn nor was paid any additional fees for services as a director.

(5) Glenn G. MacNeil has served as one of our directors since April 1, 2011. In 2013, Mr. MacNeil did not earn nor was paid any additional fees for services as a director.

(6) Alan D. Gaines was appointed a director on May 6, 2013. He is currently serving as Chairman of our Board of Directors. In 2013, Mr. Gaines did not earn nor was paid any additional fees for services as a director.

Ongoing Director Compensation in 2014

Effective January 1, 2013, our independent directors are compensated with an annual stipend of $50,000 paid in quarterly installments either in cash or common stock at the discretion of the Board of Directors. The independent directors are also eligible to participate in the annual incentive program.

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

 The following table sets forth, as of March 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, 2014, we had one class of voting securities that consisted of 52,059,975 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 March 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		3,708,532	(2)		7.1	%
Douglas C. Hewitt, Sr.		8,449,622	(3)		16.2	%
Glenn G. MacNeil		2,523,372	(4)		4.8	%
John J. McFadden		75,324			0.1	%
Michael A. Cederstrom		901,726			1.7	%
Joseph P. Tate		1,238,489	(5)		2.4	%
Thomas R. Grimm		155,625	(6)		0.3	%
Directors and Officers as a Group (7 persons)		17,052,690			32.6	%

(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 3,708,532 shares owned by Alan D. Gaines. The address of Mr. Gaines is 100 South Doheny Drive, Penthouse 7 (Apt. 1107), Los Angeles, CA 90048.

(3) Consists of the following shares owned by Douglas C. Hewitt, Sr., or of which Mr. Hewitt may be deemed to be the beneficial owner: (i) 4,449,622 shares held in the name of Douglas C. Hewitt, Sr. and (ii) 4,000,000 shares held in the name of the D. Mack Trust by virtue of being the trustee of the trust. The address of the D. Mack Trust is 1775 Stone Ridge Drive, Bountiful, UT 84010.

(4) Consists of the following shares owned by Glenn G. MacNeil, or of which Mr. MacNeil may be deemed to be the beneficial owner: (i) 1,173,818 shares held in the name of Glenn G. MacNeil, and (ii) 1,349,554 shares held in the name of Carolyn Kovachik-MacNeil, Mr. MacNeil’s spouse. The address of Mr. MacNeil, his spouse and MacKov is 521-11 Bronte Road, Oakville, Ontario, Canada, L6L 0E1.

(5) 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.

(6) Consists of the 155,625 shares owned by Thomas R. Grimm. In addition, Mr. Grimm is a holder of 13,320 outstanding warrants exercisable within 3 years from the date of issuance. The address of Mr. Grimm is 1985 Stone Hollow Drive, Bountiful, Utah 84010.

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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. Many of these transactions have involved related parties, including our directors and executive officers, existing shareholders, and their affiliates. In addition, we obtained many of our initial leases in transactions with our related parties.

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. We have taken steps to reduce or eliminate related-party transactions, and we intend to limit related-party transactions in the future. Many of our related parties have recently entered into transactions to divest working interests and overriding royalty interests in our leases, and divest their ownership interests in entities that have an ongoing relationship with Richfield.

Each of the related-party transactions described below were reviewed and approved by a majority vote of our Board of Directors 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. Douglas C. Hewitt, Sr., President, Chief Executive Officer and Director

Affiliates of Douglas C. Hewitt, Sr., our President and Chief Executive Officer and one of our Directors, have entered into a variety of transactions with Richfield as described below.

The D. Mack Trust

Mr. Hewitt is the sole beneficiary of The D. Mack Trust, an irrevocable trust established by Mr. Hewitt on May 15, 2009.

· As of March 31, 2014, the D. Mack Trust had ORRIs ranging from 0.50% to 3.625% in 1,636 net acres leased by Richfield in Kansas and Oklahoma, all of which were in place prior to January 1, 2012 or were purchased from MacKov in November 2012 (as described in further detail below).

The D. Mack Trust received $23,284 and $12,489 in royalties in 2013 and 2012, respectively, from the overriding royalty interests described above.

Mountain Home Petroleum Business Trust

Mr. Hewitt was a 33.4% beneficiary of, and a trustee of, the Mountain Home Petroleum Business Trust, a Utah business trust (“Mountain Home”) during the period beginning January 1, 2011 and ending December 31, 2012. On December 19, 2012, Mr. Hewitt resigned as a Trustee of Mountain Home and as of December 31, 2012, Mr. Hewitt was no longer a beneficiary of Mountain Home.

Prior to January 1, 2012, Mountain Home obtained the overriding royalty interests in conjunction with the establishment of the Utah Overthrust Agreement and the Liberty Prospect Agreement. No oil or natural gas has been extracted from the HUOP Freedom Trend Prospect or the HPI Liberty #1 Well and Liberty Prospect and therefore no royalties have been paid on those prospects.

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Zions Energy Corporation

Zions Energy Corporation, a Utah corporation (“Zions”), is a wholly-owned subsidiary of Mountain Home and was affiliated with Mr. Hewitt by virtue of his beneficial interest in Mountain Home. Mr. Hewitt’s beneficial interest in Zions terminated concurrently with the termination of his affiliation with Mountain Home.

Richfield participated in the following transactions with Zions in 2012:

· In three transactions in February and March 2012, Richfield sold an aggregate of 1.00% working interest in the Moroni #1-AXZH Well and the 320 acres leasehold for total cash consideration of $77,561 to Zions. This purchase was made on the same terms as other third-party transactions that were completed in December 2011 and January 2012;

· In two transactions in February and March 2012, Richfield sold an aggregate of 3.00% working interest in the Koelsch Field, including the requirement to participate in the RFO Koelsch #25-1 Well, for total cash consideration of $9,090 to Zions. This purchase was made on the same terms as other third-party transactions that were completed in December 2011 and March 2012;

· In May 2012, Richfield received $50,000 in cash plus it acquired a 1.00% working interest in the Moroni #1-AXZH Well and the 320 acres leasehold from Zions in exchange for a 1.50% carried interest in the first well to be drilled in the shallow zone on the HUOP Freedom Trend Prospect. This exchange was made on the same terms as another third-party transaction that was completed in May 2012; and

· In August 2012, Zions loaned us $50,000 and we issued a Note Payable to Zions at 6.0% per annum, due September 30, 2012. In conjunction with the loan, we granted warrants to purchase 15,000 shares of our common stock, exercisable at $5.00 per share and expiring on September 29, 2013. The warrants were valued at $3.68 using the Black-Scholes option valuation model and were expensed on the date of grant. We repaid the note in September 2012, including $247 in interest.

During 2012, Zions received $4,662 in revenues from oil sales from our Koelsch Field.

For a description of amounts paid to Mr. Hewitt as compensation for Mr. Hewitt’s service as our President, Chief Executive Officer and one of our Directors, see “Item 11. Executive Compensation.”

B. Glenn G. MacNeil, Chief Financial Officer and  Director

Glenn G MacNeil, our Chief Financial Officer and one of our Directors, along with his spouse, owns 100% of the ownership interests in MacKov Investments Limited, an Ontario, Canada incorporated private company (“MacKov”).

Richfield participated in the following transactions with MacKov between January 1, 2012 and March 31, 2014:

· In November 2012, MacKov sold ORRIs ranging from 0.25% to 2.25% in 1,127 net acres of oil and natural gas properties located in Kansas to the D. Mack Trust and one unaffiliated investor;

· In February 2012, MacKov purchased a 1.50% working interest in the Koelsch Field from Richfield for cash of $4,545. In October 2012, MacKov sold all of its 5.00% working interest in the Koelsch Field to Richfield for $262,500. The consideration consisted of MacKov exercising 154,753 outstanding warrants to purchase 154,753 shares of our common stock valued at $247,605 or $1.60 per share and our issuance of 5,958 shares of our common stock valued at $14,895 or $2.50 per share. Each of these transactions were completed on the same terms as other independent third-party transactions in the Keolsch Field at or around the time of the transaction;

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· In October 2012, MacKov sold all of its 1.00% carried working interest BPO and APO in the HPI Liberty #1 Well, its 1.00% working interest BPO and APO in the Liberty Prospect, its 2.25% working interest BPO and 1.75% working interest APO in the HPI Liberty #1 Well and Liberty Prospect to Richfield in exchange for 96,800 shares of common stock, valued at $242,000 or $2.50 per share. Each of these transactions were completed on the same terms as our other independent third-party transactions at our around the time of the transactions;

· In October 2012, MacKov sold all of its 0.50% working interest in the deep zones and its 0.25% working interest in the shallow zones of the HUOP Freedom Trend Prospect to Richfield in exchange for 25,000 shares of common stock, valued at $62,500 or $2.50 per share. Each of these transactions were completed on the same terms as our other independent third-party transactions at our around the time of the transaction;

· In February 2012, MacKov purchased a 0.50% working interest in the Moroni #1-AXZH Well and the 320 acre leasehold from Richfield for cash of $38,781. This purchase was made on the same terms as other independent third-party transactions in the Independence Field that were completed at or around the time of the transaction. On June 30, 2012, in connection with our sale to Skyline Oil, MacKov sold its 0.50% working interest in the Moroni #1-AXZH Well and the surrounding 320 acres to Skyline Oil;

· On June 30, 2012, MacKov settled a short term loan in the amount of $217,050 along with $82,172 of interest for a total of $299,222 for consideration consisting of a payment from Richfield to MacKov of $287,713 in cash and MacKov’s election to exercise warrants to purchase 7,193 shares of common stock at an exercise price of $11,509 or $1.60 per share. Each of these transactions were completed on the same terms as our other independent third-party loan transactions at or around the time of the transaction;

· In November 2012, MacKov granted a demand loan to Richfield in the amount of $65,000 with interest accruing at 10.0% per annum, secured by a 1% working interest in certain HUOP Freedom Trend Prospect leases (the “MacKov Demand Note”). On December 31, 2012, the Company paid all accrued interest under the MacKov Demand Note, in the amount of $727 and the principal was transferred to an independent third party.

As of March 31, 2014, MacKov has no working interests or ORRIs in oil or natural gas properties that we control or in which we own an interest and MacKov has no warrants outstanding to purchase our common stock.

For the years ended December 31, 2013 and 2012, MacKov received $0 and $12,642, respectively, in royalties relating to ORRIs and oil sales from working interest from Kansas leases including the Koelsch Field that were previously owned by MacKov.

For a description of amounts paid to Mr. MacNeil and MacKov as compensation for Mr. MacNeil’s service as our Chief Financial Officer and one of our Directors, see “Item 11. Executive Compensation.”

C. Joseph P. Tate, a Director

Joseph P. Tate became one of our directors effective March 31, 2012. Mr. Tate has entered into the following transactions with Richfield between January 1, 2012 and March 31, 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. In March 2014, the Company consolidated and replaced the Tate leases with a new lease covering a combined 1,823 gross acres. The initial bonus for the new lease totals $182,308 and represents a prepayment of all delay rentals for the 10 year primary term commencing on April 15, 2014. The initial bonus amount is similar to third party 10 year primary term leases obtained by the Company in the HUOP Freedom Trend Prospect during 2013. 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;

· In March 2012, Mr. Tate and Richfield agreed to the repayment of a $100,000 outstanding payable, including interest of $18,000, through the issuance of 47,200 shares of common stock, valued at $118,000, or $2.50 per share.

· In October 2012, MacKov assigned warrants to purchase 88,057 shares of common stock to Joseph P. Tate and several unaffiliated investors for total cash consideration of $17,611, or $0.20 per warrant. Mr. Tate and the other unaffiliated investors then exercised the warrants to purchase 88,057 shares of common stock for total cash consideration of $140,889, or $1.60 per share.

· In May 2013, Mr. Tate purchased 250,000 shares of common stock of the Company for cash in the amount of $200,000, or $0.80 per share. The shares are subject to a ratchet provision that in the event the Company sells shares of common stock or convertible securities at any time prior to December 31, 2013 at a price per share less than $0.80, the Company shall issue an additional amount of shares of common stock to make the effective price of the shares of common stock equal to the price per share of common stock that were sold for less than $0.80. In addition, the Company granted warrants to Mr. Tate to purchase up to 125,000 shares of common stock with an exercise price of $1.00 that expire in May 2014. In January 2014, 262,821 shares of common stock were issued pursuant to the terms of this provision.

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For a description of amounts paid to Mr. Tate as compensation for services as one of our directors, see “Item 11. Executive Compensation.”

D. Alan D. Gaines, Chairman of the Board

Alan D. Gaines, Chairman of the Board of Directors, is a party to the following transaction with the Company between January 1, 2012 and March 31, 2014:

· In May 2013, the Company announced the appointment of Alan D. Gaines as Chairman of the Board of Directors and as part of his compensation package, the Company awarded Mr. Gaines 3,500,000 common stock options with an exercise price of $1.00 which expire in May 2020. The options vest 50% upon the earlier of six months or the Company obtaining funding in excess of $3 million, 25% after one year and 25% after two years. In January 2014, the options were cancelled and 4,908,532 shares of common stock were issued at value of $1,472,560 or $0.30 per share.

For a description of amounts paid to Mr. Gaines as compensation for services as one of our directors, see “Item 11. Executive Compensation.”

Director Independence

Our common stock is currently quoted on the OTCQX, 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 Thomas R. Grimm are considered independent based on the NYSE listing rules. These independent directors currently comprise the majority membership of each standing Board committee described in this annual report.

Alan D. Gaines, Douglas C. Hewitt, Sr. and Glenn G. MacNeil are not considered independent directors due to their employment as our executive officers.

63

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Mantyla McReynolds, LLC audited our financial statements for the years ended December 31, 2013 and 2012.

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 2013 and 2012, 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.

Audit and Related Fees

The following table sets forth the aggregate fees billed by Mantyla McReynolds for professional services rendered in fiscal years ended December 31, 2013 and 2012.

	2013		2012
Audit Fees (1)	$	174,733	$	211,441
Audit-Related Fees (2)	$	-	$	-
Tax Fees (3)	$	25,279	$	19,420
All Other Fees	$	-	$	-

(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.

64

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 incorporated herein by reference.

65

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.

	RICHFIELD OIL & GAS COMPANY
Dated:  April 14, 2014	By:	/s/ DOUGLAS C. HEWITT, SR.
		Douglas C. Hewitt, Sr.
		Chief Executive Officer
Dated:  April 14, 2014	By:	/s/ GLENN G. MACNEIL
		Glenn G. MacNeil.
		Chief Financial 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/ DOUGLAS C. HEWITT, SR.	President, Chief Executive Officer	April 14, 2014
Douglas C. Hewitt, Sr.	(Principle Executive Officer)
/s/ GLENN G. MACNEIL	Chief Financial Officer and Director	April 14, 2014
Glenn G. MacNeil	(Principle Financial Officer)
/s/ ALAN D. GAINES	Executive Chairman	April 14, 2014
Alan D. Gaines
/s/ JOHN J. MCFADDEN	Director	April 14, 2014
John J. McFadden
/s/ JOSEPH P. TATE	Director	April 14, 2014
Joseph P. Tate
/s/ THOMAS R. GRIMM	Director	April 14, 2014
Thomas R. Grimm

66

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Richfield Oil & Gas Company Audited Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2013 and 2012	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2013 and 2012	F-4
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2013 and 2012	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013 and 2012	F-7
Notes to Consolidated Financial Statements	F-8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors

Richfield Oil & Gas Company

175 South Main Street, Suite 900

Salt Lake City, UT 84111

We have audited the accompanying consolidated balance sheets of Richfield Oil & Gas Company (“the Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years 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 audits.

We conducted our audits 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 audits 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 audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Richfield Oil & Gas Company as of December 31, 2013 and 2012, and the results of its operations and its cash flows for the years 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 2 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 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Salt Lake City, UT

April 14, 2014

F-2

 RICHFIELD OIL & GAS COMPANY

 Consolidated Balance Sheets

December 31, 2013 and December 31, 2012

ASSETS
	December 31,
	2013			2012
Current assets
Cash and cash equivalents	$	60,395		$	286,013
Restricted Cash		153,348			-
Accounts receivables		322,604			387,803
Deposits and prepaid expenses		77,475			390,750
Total current assets		613,822			1,064,566
Properties and equipment, at cost - successful efforts method:
Proved properties		7,139,663			6,581,725
Unproved properties		14,095,020			14,164,053
Well and related equipment		1,997,913			1,024,972
Accumulated depletion, depreciation and amortization		(1,224,523	)		(923,083	)
		22,008,073			20,847,667
Other properties and equipment		219,231			236,212
Accumulated depreciation		(203,743	)		(188,411	)
		15,488			47,801
Total assets	$	22,637,383		$	21,960,034
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable	$	2,049,750		$	1,578,510
Accrued expenses and other payables		3,104,485			1,368,276
Current portion of notes payable		1,338,524			1,487,419
Convertible notes payable, net of discount of $120,264 and $0
at 12/31/13 and 12/31/12, respectively		1,861,386			1,352,560
Capital lease obligations		135,311			15,748
Current portion of asset retirement obligations		48,000			-
Derivative liability		310,156			-
Total current liabilities		8,847,612			5,802,513
Long-term liabilities
Notes payable, net of current portion		-			1,674,691
Asset retirement obligations, net of current portion		394,075			482,157
Total long-term liabilities		394,075			2,156,848
Total liabilities		9,241,687			7,959,361
Commitments and contingencies
Stockholders' equity
Common stock, par value $.001; 250,000,000 authorized;
39,906,770 shares and 32,518,192 shares issued and outstanding
at 12/31/2013 and 12/31/2012, respectively		39,907			32,518
Additional paid-in capital		51,360,380			45,147,563
Accumulated deficit		(38,004,591	)		(31,179,408	)
Total stockholders' equity		13,395,696			14,000,673
Total liabilities and stockholders' equity	$	22,637,383		$	21,960,034

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

F-3

 RICHFIELD OIL & GAS COMPANY

 Consolidated Statements of Operations

 For the Years Ended December 31, 2013 and 2012

	Year Ended
	December 31,
	2013			2012
Revenues
Oil and natural gas sales	$	1,046,336		$	952,566
Total revenues		1,046,336			952,566
Operating expenses
Production expenses		900,129			764,457
Production taxes		41,782			30,862
Exploration		136,431			167,212
Lease expiration		182,032			25,293
Depletion, depreciation, amortization and accretion		382,690			261,739
General and administrative expenses		4,571,642			7,383,227
Asset retirement obligation expenses		161,901			-
Gain on sale of assets		(105,106	)		(471,392	)
Total expenses		6,271,501			8,161,398
Loss from operations		(5,225,165	)		(7,208,832	)
Other income (expenses)
Gain on settlement of liabilities		30,367			20,769
Loss on extinguishment of debt		(1,103,702	)		-
Gain on derivative valuation		756,776			-
Interest and finance expenses		(1,257,143	)		(1,104,612	)
Interest income		850			299,879
Total other income (expenses)		(1,572,852	)		(783,964	)
Loss before income taxes		(6,798,017	)		(7,992,796	)
Income tax provision		(1,567	)		(400	)
Net loss	$	(6,799,584	)	$	(7,993,196	)
Net loss per common share - basic and diluted	$	(0.19	)	$	(0.28	)
Weighted average shares outstanding – basic and diluted		36,393,603			28,873,656

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

F-4

RICHFIELD OIL & GAS COMPANY

Consolidated Statement of Stockholders' Equity

For the Years Ended December 31, 2013 and 2012

	Common Stock
							Additional					Total
							Paid-In		Accumulated			Stockholders'
	Shares			Par			Capital		Deficit			Equity
Balance - December 31, 2011		27,088,744		$	27,089		$	31,232,334	$	(22,551,466	)	$	8,707,957
Issued 1,806,203 common stock for oil and gas properties and JIBs (valued between $1.60 and $2.50 per share)		1,806,203			1,806			4,392,342		-			4,394,148
Issued 282,511 common stock to a related party for oil and gas properties (valued between $1.60 and $2.50 per share)		282,511			283			566,717		-			567,000
Issued 1,443,378 common stock for directors', employees and consultants' compensation		1,443,378			1,443			3,608,001		-			3,609,444
Sale of 1,335,277 common stock and 935,196 warrants for cash between $1.60 and $2.50 per share		1,335,277			1,335			3,125,917		-			3,127,252
Issued 77,950 common stock as settlement of accounts payables including accrued interest		77,950			78			194,797		-			194,875
Issued 403,651 common stock as settlement of notes payable		403,651			404			949,528		-			949,932
Issued 7,193 common stock for related party payment of interest and exercise of warrants		7,193			7			11,502		-			11,509
Return of 25,000 common stock for cancellation from related party		(25,000	)		(25	)		-		(62,475	)		(62,500	)
Return of 229,000 common stock for cancellation from unaffiliated investors related to the exchange of oil and gas properties		(229,000	)		(229	)		-		(572,271	)		(572,500	)
Issued 184,072 common stock in exchange for convertible preferred stock redemption (see NOTE 11 PREFERRED STOCK)		184,072			184			389,331		-			389,515
Exercised 143,213 common stock warrants		143,213			143			228,998		-			229,141
Issued 1,017,301 common stock warrants (see NOTE 13 WARRANTS TO PURCHASE COMMON STOCK)		-			-			448,096		-			448,096
Net loss for the year		-			-			-		(7,993,196	)		(7,993,196	)
Balance - December 31, 2012		32,518,192		$	32,518		$	45,147,563	$	(31,179,408	)	$	14,000,673

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

F-5

RICHFIELD OIL & GAS COMPANY

 Consolidated Statement of Stockholders' Equity

For the Years Ended December 31, 2013 and 2012

	Common Stock
							Additional						Total
							Paid-In			Accumulated			Stockholders'
	Shares			Par			Capital			Deficit			Equity
Balance - December 31, 2012		32,518,192		$	32,518		$	45,147,563		$	(31,179,408	)	$	14,000,673
Sale of 1,166,750 common stock and 765,375 warrants for cash		1,166,750			1,167			1,067,833			-			1,069,000
Issued 10,000 common stock as partial payment on purchase of new leases		10,000			10			8,490			-			8,500
Issued 1,102,064 common stock and 21,250 warrants for creditors, consultants, directors, officers, and other employees outstanding payables		1,102,064			1,102			888,730			-			889,832
Issued 561,307 common stock for consultants and directors compensation		561,307			561			345,031			-			345,592
Return of 25,626 common stock for cancellation from unaffiliated investors related to the sale of oil and gas properties		(25,626	)		(25	)		-			(25,599	)		(25,624	)
Issued 4,512,874 common stock for payment of debt, interest, and extension and conversion incentives.		4,512,874			4,513			2,604,263			-			2,608,776
Issued 59,644 common stock per ratchet provision on agreement		61,209			61			56,600			-			56,661
Issued 525,000 warrants for consultants compensation		-			-			49,475			-			49,475
Issued 3,139,853 warrants with debt as a debt discount, for reduction of debt, and sale of ORRI		-			-			557,481			-			557,481
Record derivative liability for stock issued for cash		-			-			(344,572	)		-			(344,572	)
Adjustment for repricing and modification of warrants		-			-			184,477			-			184,477
Employee stock option amortization		-			-			795,009			-			795,009
Net loss for the year		-			-			-			(6,799,584	)		(6,799,584	)
Balance - December 31, 2013		39,906,770		$	39,907		$	51,360,380		$	(38,004,591	)	$	13,395,696

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

F-6

 RICHFIELD OIL & GAS COMPANY

 Condensed Consolidated Statements of Cash Flows

 For the Years Ended December 31, 2013 and 2012 

	Years Ended
	December 31,
	2013			2012
Cash flows from operating activities:
Net loss	$	(6,799,584	)	$	(7,993,196	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion		382,690			261,739
Asset retirement obligation release on plugged wells		(39,000	)		-
Gain on settlement of liabilities		(30,367	)		(20,769	)
Accrued interest income		-			(299,812	)
Loss on extinguishment of debt		1,103,702			-
Gain on derivative liability		(756,776	)		-
Capitalized interest on notes payable		16,317			91,100
Amortization of pre-paid interest		6,164			115,256
Lease expirations		182,032			25,293
Gain on sale of assets		(105,106	)		(471,392	)
Amortization of debt discounts		218,309			220,552
Issuance of common stock, options and warrants for services and other expenses		1,627,611			3,694,628
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivables		128,649			(249,065	)
Decrease (increase) in deposits and prepaid expenses		273,906			54,384
Decrease (increase) in other assets		-			(119,421	)
Increase (decrease) in accounts payable		51,701			663,890
Increase (decrease) in accrued expenses and other payables		2,745,718			571,218
Increase (decrease) in due to directors		-			(27,934	)
Increase (decrease) in due to related parties		-			(43,307	)
Net cash used in operating activities		(994,034	)		(3,526,836	)
Cash flows from investing activities:
Investment in oil and gas properties, including wells and related equipment		(1,478,594	)		(2,202,128	)
Investment in other properties and equipment		-			(38,597	)
Proceeds from sale of assets		467,200			2,307,404
Net cash provided by (used in) investing activities		(1,011,394	)		66,679
Cash flows from financing activities:
Proceeds from notes and convertible notes payable		1,921,811			754,276
Payments on notes and convertible notes payable		(1,004,798	)		(721,303	)
Restricted cash for settlement of note and litigation (see NOTE 19 LEGAL PROCEEDINGS)		(153,348	)		-
Proceeds from related party notes payable		-			111,319
Payments on related party notes payable		-			(337,713	)
Payments on capital lease obligation		(60,233	)		(35,479	)
Proceeds from issuance of convertible preferred stock		-			285,000
Proceeds from issuance of warrants		7,378			296,520
Proceeds from issuance of common stock - net of issuance costs		1,069,000			3,356,393
Net cash provided by financing activities		1,779,810			3,709,013
Net increase (decrease) in cash and cash equivalents		(225,618	)		248,856
Cash and cash equivalents - beginning of period		286,013			37,157
Cash and cash equivalents - end of period	$	60,395		$	286,013
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	64,290		$	463,409
Cash paid during the period for income taxes	$	1,567		$	400
Non-cash financing and investing activities:
Redemption of preferred stock and payment of preferred stock dividends
through issuance of common stock	$	-		$	389,515
Purchase of oil and gas properties and conversion of JIB receivables billed to
working interest holders through issuance of common stock and warrants	$	8,500		$	4,961,148
Capitalized oil and gas properties included in accounts payable	$	951,700		$	-
Purchase of properties through exchange of property and reduction of payables and notes payable	$	71,332		$	779,000
Sale of oil and gas properties for return of common stock	$	45,625		$	572,500
Cancellation of lease in full satisfaction of accounts payable	$	-		$	180,000
Conversion of pre-paid expenses, payables, and notes payable through issuance
of common stock and warrants	$	3,351,610		$	1,793,551
Conversion of accounts payable through issuance of note payable	$	21,000		$	186,229
Capitalized accrued interest on notes payable	$	-		$	70,789
Derivative liability on common stock issued	$	344,572		$	-
Conversion of notes payable through issuance of convertible notes payable	$	-		$	1,328,000
Conversion of convertible notes payable through issuance of notes payable	$	-		$	1,117,500
Amortization of plugged wells	$	41,766		$	-
Capitalized Leased Equipment	$	179,796
Capitalized asset retirement obligations	$	57,021		$	144,287
Write down of asset retirement obligation on sold properties	$	67,115		$	-

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

F-7

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

NOTE 1     ORGANIZATION AND NATURE OF BUSINESS

Richfield Oil & Gas Company (the “Company,” “Richfield” or “ROIL”) is a Nevada corporation headquartered in Salt Lake City, Utah which was incorporated on April 8, 2011. The Company is engaged in the exploration, development and production of oil and natural gas in the states of Kansas, Oklahoma, Utah and Wyoming. The Company’s common stock trades on the OTCQX under the symbol “ROIL”.

Contemporaneously with ROIL’s incorporation, the Company merged (the “HPI Merger”) with its predecessor company, Hewitt Petroleum, Inc., a Delaware corporation which was incorporated on May 17, 2008 (“HPI”). In connection with the HPI Merger, HPI was merged out of existence and the Company assumed all of the assets and liabilities of HPI and the Company became the parent company of HPI’s two wholly owned subsidiaries, Hewitt Energy Group, Inc., a Texas corporation (“HEGINC”) and Hewitt Operating, Inc., a Utah corporation (“HOPIN”). The Plan of Merger required that all HPI common stock be exchanged on a one-for-one basis for ROIL common stock and that ROIL assume all of the liabilities of HPI as of the effective date of the HPI Merger. As a result, the Company’s historical financial statements are a continuation of the financial statements of HPI. In addition, effective March 31, 2011, HPI entered into a Stock Exchange Agreement with Freedom Oil & Gas, Inc., a Nevada corporation (“Freedom”), which called for the exchange of stock in HPI for all of the outstanding stock of Freedom (the “Freedom Acquisition”). Upon completion of the Freedom Acquisition, it became a wholly owned subsidiary of the Company from March 31, 2011 until June 20, 2011 when Freedom was merged into ROIL with ROIL being the surviving entity.

On July 27, 2012 the Company formed a new wholly owned subsidiary, HR Land Group, LLC, a Utah Limited Liability Company, (“HR Land”). HR Land’s purpose is to acquire oil and gas leases.

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, HEGINC, HOPIN and HR Land. All significant intercompany transactions and balances have been eliminated in consolidation.

The Company has been involved in leasing, exploring and drilling in Kansas, Oklahoma, Utah and Wyoming since its formation. The Company is participating in over 35,000 acres of leasehold, seismic surveys, and numerous drilling projects in these states.  The Company uses proven technologies and drilling and production methods that are both efficient and environmentally sound.

NOTE 2     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. The Company sustained a net loss for the year ended December 31, 2013 of $6,799,584 and a net loss for the year ended December 31, 2012 of $7,993,196, and has an accumulated deficit of $38,004,591 as of December 31, 2013.

The Company intends to make its planned capital expenditures in order to continue its drilling programs, but does not have sufficient realized revenues or operating cash flows in order to finance these activities internally. As a result, the Company intends to seek financing in order to fund its working capital and capital expenditure needs.

The Company has been able to meet its short-term needs through loans from officers and third parties; sales of working interest in its oil and gas properties; private placements of equity securities; and the settlement of liabilities by issuing common stock.  The Company may seek additional funding through sales of working interest in its oil and gas properties; the issuance of debt; preferred stock; common stock; or a combination of these items. Any proceeds received from these items could provide the needed funds for continued operations and drilling programs. The Company can provide no assurance that it will be able to obtain sufficient additional financing that it needs to develop its properties and alleviate doubt about its ability to continue as a going concern. If the Company is able to obtain sufficient additional financing proceeds, the Company cannot be certain that this additional financing will be available on acceptable terms, if at all. To the extent the Company raises additional funds by issuing equity securities, the Company’s stockholders may experience significant dilution. Any debt financing, if available, may involve restrictive covenants that impact the Company’s ability to conduct business. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

F-8

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

NOTE 3     SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”).

Principles of Consolidation and Presentation

The Company was incorporated in Nevada on April 8, 2011. Contemporaneously with the incorporation, the Company merged with its predecessor company, HPI. In connection with the HPI Merger, HPI was merged out of existence and the Company assumed all of the assets and liabilities of HPI. As a result, the Company’s historical financial statements are a continuation of the financial statements of HPI. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, HEGINC, HOPIN, HR Land, HOI KS and HOI UT. All significant intercompany transactions and balances have been eliminated in consolidation.

Cash and Cash Equivalents

The Company considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents. Cash equivalents consist primarily of cash on hand, interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available on a daily or weekly basis and are highly liquid in nature.  If the balances are greater than $250,000, the Company does not have FDIC coverage on the entire amount of bank deposits.  The Company believes this risk is minimal.  

Accounts Receivable

Trade accounts receivable are primarily from oil and natural gas sales and net amounts due from Joint Interest Billings (“JIBs”) from working interest holders in the Company’s oil and gas properties in which we are the operator. These trade accounts receivables are recorded at the invoiced amount, net of allowances for doubtful amounts. The Company routinely reviews outstanding accounts receivable balances for estimated uncollectible accounts and regularly reviews collectability and establishes or adjusts the allowances for doubtful accounts receivables using the specific identification method and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2013 and 2012, the Company had no allowance for doubtful accounts.

Oil and Gas Properties Accounting Policies

The Company accounts for oil and gas properties by the successful efforts method. Under this method of accounting, costs relating to the acquisition and development of proved areas are capitalized when incurred. 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.  As discussed in NOTE 10 ASSET RETIREMENT OBLIGATIONS, asset retirement costs are recognized when the asset is placed in service, and are depleted over proved reserves using the units of production method. 

F-9

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

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. The Company did record an impairment allowance for expiring leaseholds on proven properties for the year ended December 31, 2013. The Company recorded no impairment allowance on proven properties for the year ended December 31, 2012.

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, 2013 and 2012, 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, 2013 and 2012.

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.

Other Property and Equipment

Other property 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 seven 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.  The Company has not recognized any impairment losses on non-oil and gas long-lived assets.  

Asset Retirement Obligations

Asset retirement obligation relates to future costs associated with plugging and abandonment of crude oil and natural gas wells, removal of equipment and facilities from leased acreage and returning the land to its original condition. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, external estimates to plug and abandon the wells in the future and federal and state regulatory requirements. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset.  The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.  If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

F-10

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

Revenue Recognition

Revenue from the sale of crude oil, natural gas and natural gas liquids is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer, which is usually when legal title passes to the external party. For crude oil and natural gas liquids delivery generally occurs upon pick up at the field tank battery and for natural gas delivery occurs at the pipeline delivery point. Revenue is not recognized for the production in tanks, or oil in pipelines that has not been delivered to the purchaser.  Revenue is measured net of discounts and royalties. Royalties and severance taxes are incurred based upon the actual price received from the sales. The Company uses the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation.  As of December 31, 2013 and 2012, the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells.

Stock-Based Compensation

The Company has accounted for stock-based compensation under the provisions of FASB ASC 718.   This standard requires the Company to record an expense associated with the fair value of stock-based compensation.  The Company uses the Black-Scholes option valuation model to calculate the value of options and warrants at the date of grant.  Option and warrant pricing models require the input of highly subjective assumptions, including the expected price volatility.  Changes in these assumptions can materially affect the fair value estimate.   

Stock Issuance

The Company records the stock-based awards issued to consultants and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable, using the measurement date guidelines enumerated in FASB ASC 505.

Income Taxes

The Company accounts for income taxes under FASB ASC 740.  Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.

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. The Company has examined the tax positions taken in its tax returns and determined that there are no uncertain tax positions. As a result, the Company has recorded no uncertain tax liabilities in its consolidated balance sheet.

Loss Per Common Share

Basic earnings per share (“EPS”) are computed by dividing net income (loss) (the numerator) by the weighted average number of common shares outstanding for the period (the denominator).  Diluted EPS is computed by dividing net income (loss) by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period.  Potential common shares include stock options, warrants, and restricted stock.  The number of potential common shares outstanding relating to stock options, warrants, and restricted stock is computed using the treasury stock method.

As the Company has incurred losses for the years ended December 31, 2013 and 2012, the potentially dilutive shares are anti-dilutive and are thus not added into the loss per share calculations. As of December 31, 2013 and 2012, there were 11,937,087 and 2,707,898 potentially dilutive shares, respectively.

Use of Estimates

The preparation of financial statements under GAAP in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  The most significant estimates relate to proved oil and natural gas reserve volumes, certain depletion factors, future cash flows from oil and gas properties, estimates relating to certain oil and natural gas revenues and expenses, valuation of share based compensation, valuation of asset retirement obligations, estimates of future oil and natural gas commodity pricing and the valuation of deferred income taxes.  Actual results may differ from those estimates.

F-11

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

Impairment

FASB ASC 360 requires long-lived assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  There was no impairment identified at December 31, 2013 and 2012.

New Accounting Pronouncements

From time to time, new accounting pronouncements are issued by 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.

Reclassifications

Certain prior period balances have been reclassified to conform to the current period presentation. Such reclassifications had no impact on net loss, statements of cash flows, working capital or equity previously reported.

Reverse Stock Split

As more fully described in NOTE 12 COMMON STOCK, effective October 23, 2012, the Company implemented a 1-for-10 reverse stock split of its issued and outstanding common stock. Under the guidance of FASB ASC 505, all common share and per common share information in the accompanying consolidated financial statements and these notes to the financial statements have been retroactively restated to reflect the reverse common stock split.

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

The Company qualifies as an “emerging growth company,” as defined in Section 2(a) of the Securities Act of 1933 (the “Securities Act”) as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As such, the Company is 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. The Company has elected to take advantage of the benefits of this extended transition period. The Company’s financial statements may therefore not be comparable to those of companies that comply with such new or revised accounting standards.

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

F-12

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

NOTE 4     OIL AND NATURAL GAS PROPERTIES

Acquisitions for the year ended December 31, 2012

On January 1, 2012, the Company purchased a 1.00% working interest in the deep zones and 0.50% working interest in the shallow zones in the HUOP Freedom Trend Prospect located in Sanpete County, Utah from two unaffiliated investors for a value totaling $141,857 in exchange for the issuance of 50,000 shares of common stock for a value of $125,000, or $2.50 per share plus the cancelation of $16,857 of JIBs accounts receivable owed to the Company by the investors.

On January 1, 2012, the Company purchased a 0.25% working interest BPO and APO in the HPI Liberty #1 Well located in Juab County, Utah from an unaffiliated investor for a value totaling $22,307 in exchange for the issuance of 4,853 shares of common stock for a value of $12,133, or $2.50 per share plus the cancelation of $10,174 of JIBs accounts receivable owed to the Company by the investor.

On March 30, 2012, the Company acquired a 405 acre lease and lease extension of 1,416 acres for the HUOP Freedom Trend Prospect located in Sanpete County, Utah from an unaffiliated investor, at that time, for a value totaling $383,200 in exchange for the issuance of 153,280 shares of common stock for a value of $383,200, or $2.50 per share. The Company capitalized $289,316 as a result of having a 75.50% working interest and the remaining balance of $93,884 was billed to the other 24.50% HUOP Freedom Trend Prospect working interest holders. On March 31, 2012, this unaffiliated investor, Joseph P. Tate, became a Director of the Company.

On June 30, 2012, the Company acquired a 25.00% working interest in the Perth Field located in Sumner County, Kansas from two unaffiliated investors in exchange for an agreement to provide the investors with an aggregate 10.00% total carried interest in a certain $800,000 work plan in the Perth Field that includes drilling one new well, three well recompletions, and work on a salt water disposal well. In conjunction with this transaction, the Company sold 5.00% of the working interest received with a 5.00% carried interest in this same work plan to another unaffiliated investor. These transactions resulted in the Company acquiring a net 10.00% working interest whereby the Company’s working interest increased from 75.00% to 85.00%. This work plan commenced in December 2012.

On October 1, 2012, the Company purchased a 7.00% working interest in the Koelsch Field located in Stafford County, Kansas, from two unaffiliated investors for a value totaling $367,500 in exchange for the issuance of 195,544 shares of common stock. Of these 195,544 shares of common stock, 60,700 shares were valued at $151,750, or $2.50 per share and the remaining 134,844 shares of common stock were issued by exercising warrants with an exercise price of $1.60 per warrant or $215,750.

On October 1, 2012, the Company purchased a 5.00% working interest in the Koelsch Field located in Stafford County, Kansas, from MacKov Investments Limited, a related party, for a value totaling $262,500 in exchange for the issuances of 160,711 shares of common stock. Of these 160,711 shares of common stock, 5,958 shares were valued at $14,895, or $2.50 per share and the remaining 154,753 shares of common stock were issued by exercising warrants held by MacKov with an exercise price of $1.60 per warrant or $247,605. This purchase was made on the same terms as other unaffiliated investor transactions completed in October 2012 (see NOTE 16 RELATED PARTY TRANSACTIONS).

On October 1, 2012, the Company purchased a 21.00% working interest in the Prescott Lease located in Stafford County, Kansas, from seven unaffiliated investors for a value totaling $643,125 in exchange for the issuance of 257,250 shares of common stock valued at $643,125, or $2.50 per share.

On October 1, 2012, the Company purchased a 9.50% working interest BPO and a 6.50% working interest APO in the HPI Liberty #1 Well located in Juab County, Utah, from four unaffiliated investors for a value totaling $468,000 in exchange for the issuance of 179,887 shares of common stock valued at $449,718, or $2.50 per share, plus the cancelation of $18,282 of JIBs accounts receivable owed to the Company by the investors.

On October 1, 2012, the Company purchased a 12.95% working interest BPO and an 8.75% working interest APO in the HPI Liberty #1 Well, located in Juab County, Utah, from six unaffiliated investors for $630,000. In addition, the Company sold a 3.0625% working interest BPO and a 2.1875% working interest APO in the HPI Liberty #1 Well and Liberty Prospect to the six investors for $192,500. The net amount of $437,500 due to the investors was paid by the issuance of 162,146 shares of common stock for a total value of $405,365, or $2.50 per share, plus the cancelation of $32,135 of JIBs accounts receivable owed to the Company by the investors.

F-13

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

On October 1, 2012, the Company purchased a 1.00% carried working interest to tanks BPO, 1.00% working interest to tanks APO, 5.25% working interest BPO and 3.75% working interest APO in the HPI Liberty #1 Well and 1.00% working interest BPO and 1.00% working interest APO in the Liberty Prospect located in Juab and Sanpete Counties, Utah, from two unaffiliated investors for a value totaling $725,965, which was paid by the issuance of 30,000 shares of common stock valued at $75,000, or $2.50 per share, the issuance of a $589,000 note payable, plus the cancelation of $61,965 of JIBs accounts receivable owed to the Company by the investors.

On October 1, 2012, the Company purchased a 1.00% carried working interest to tanks, a 2.25% working interest BPO and a 1.75% working interest APO in the HPI Liberty #1 Well and a 3.25% working interest BPO and a 2.75% working interest APO in the Liberty Prospect located in Juab County, Utah, from MacKov Investments Limited, a related party, for a value totaling $242,000 in exchange for the issuance of 96,800 shares of common stock valued at $242,000, or $2.50 per share. This purchase was made on the same terms as other unaffiliated investor transactions completed in October 2012 (see NOTE 16 RELATED PARTY TRANSACTIONS).

On October 1, 2012, the Company purchased from an unaffiliated investor a 14.50% working interest in the deep zones and a 7.25% working interest in the shallow zones of the HUOP Freedom Trend Prospect located in Sanpete County, Utah and a 2.80% working interest BPO and 2.00% working interest APO in the HPI Liberty #1 Well located in Juab County, Utah for a total of $1,956,500 which was paid by issuing 609,243 shares of common stock valued at $1,523,108, or $2.50 per share, plus the cancelation of $433,392 of JIBs and other receivables owed to the Company by the investors.

On October 1, 2012, the Company purchased a 0.50% working interest in the deep zones and a 0.25% working interest in the shallow zones of the HUOP Freedom Trend Prospect located in Sanpete County, Utah, from MacKov Investments Limited, a related party, for a value totaling $62,500 in exchange for the issuance of 25,000 shares of common stock valued at $62,500, or $2.50 per share. This purchase was made on the same terms as other Company unaffiliated investor transactions completed in October 2012 (see NOTE 16 RELATED PARTY TRANSACTIONS).

On October 26 and November 5, 2012, the Company purchased three leases containing 1,511 net acres located in the Hogback Ridge Prospect in Rich County, Utah for the sum of $17,730.

On December 1, 2012, the Company acquired 100% working interest in the Wasatch National Forest Well #16-15 and the surrounding 640 acres in Uinta County, Wyoming from an unaffiliated and existing investor for $610,000 that was paid as follows: (i) the Company paid $10,000 cash; (ii) the Company issued 164,000 shares of common stock for a total value of $410,000, or $2.50 per share; and (iii) the Company issued a $190,000 note payable to the investor.

Acquisitions for the year ended December 31, 2013

In January 2013, the Company purchased two leases in the HUOP Freedom Trend Prospect: (i) a lease totaling 111 net acres with a term of 10 years for a payment of $1,664 per year; and (ii) the City of Fountain Green Lease totaling 206 net acres with a term of 10 years and includes the right to use surplus city water for a one-time payment of $140,000.

In May 2013, the Company purchased two 5 year leases with a 5 year option to renew in the HUOP Freedom Trend Project totaling 1,328 acres for $74,387. As part of the consideration for the leases the Company issued 10,000 shares of common stock valued at $8,000 or $0.80 per share with the balance of $66,387 paid in cash.

In May 2013, the Company purchased a 10 year lease in the HUOP Freedom Trend Prospect totaling 422 acres with annual payments of $6,329.

In June 2013, the Company purchased a 5 year lease with a 5 year option to renew in two new prospects in the Central Utah Overthrust totaling 1,707 acres for $59,729 in cash.

F-14

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

Divestitures for the year ended December 31, 2012

On January 30, 2012, the Company sold a 1.00% working interest in the Moroni #1-AXZH Well and the 320 acres leasehold for cash of $77,561 to an unaffiliated investor.

On February 10, 2012, the Company sold a 0.50% working interest in the Moroni #1-AXZH Well and the 320 acres leasehold for cash of $38,781 to a related party, Zions Energy Corporation. This sale was made on the same terms as the other unaffiliated investor transaction completed in January 2012 (see NOTE 16 RELATED PARTY TRANSACTIONS).

On February 21, 2012, the Company sold a 0.25% working interest in the Moroni #1-AXZH Well and the 320 acres leasehold for cash of $19,390 to a related party, Zions Energy Corporation. This sale was made on the same terms as the other unaffiliated investor party transaction completed in January 2012 (see NOTE 16 RELATED PARTY TRANSACTIONS).

On February 22, 2012, the Company sold a 2.00% working interest in the Koelsch Field, including the requirement to participate in the RFO Koelsch #25-1 Well, for cash of $6,060 to a related party, Zions Energy Corporation. This sale was made on the same terms as other unaffiliated investor transactions completed in December 2011 (see NOTE 16 RELATED PARTY TRANSACTIONS).

On February 22, 2012 the Company sold a 1.50% working interest in the Koelsch Field, including the requirement to participate in the RFO Koelsch #25-1 Well, for cash of $4,545 to a related party, MacKov Investments Limited. This sale was made on the same terms as other unaffiliated investor transactions completed in December 2011 (see NOTE 16 RELATED PARTY TRANSACTIONS).

On February 29, 2012, the Company sold a 0.50% working interest in the Moroni #1-AXZH Well and the 320 acres leasehold for cash of $38,781 to a related party, MacKov Investments Limited. This sale was made on the same terms as the other unaffiliated investor party transaction completed in January 2012 (see NOTE 16 RELATED PARTY TRANSACTIONS).

On March 12, 2012, the Company sold a 1.00% working interest in the Koelsch Field, including the requirement to participate in the RFO Koelsch #25-1 Well, for cash of $3,030 to a related party Zions Energy Corporation. This sale was made on the same terms as other unaffiliated investor transactions completed in January 2012 (see NOTE 16 RELATED PARTY TRANSACTIONS).

On March 14, 2012, the Company sold a 0.25% working interest in the Moroni #1-AXZH Well and the 320 acres leasehold for cash of $19,390 to a related party Zions Energy Corporation. This sale was made on the same terms as the other unaffiliated investor party transaction completed in January 2012 (see NOTE 16 RELATED PARTY TRANSACTIONS).

On March 15, 2012, the Company sold a 1.00% working interest in the Koelsch Field, including the requirement to participate in the RFO Koelsch #25-1 Well, for cash of $3,030 to an unaffiliated investor.

On May 15, 2012, the Company sold a 3.00% carried interest in the first well to be drilled in the shallow zone on the HUOP Freedom Trend Prospect in exchange for $100,000 in cash and a return of a 2.00% working interest in the Moroni #1-AXZH Well and the 320 acre leasehold. There were two parties to this transaction, one was an unaffiliated investor, the other was a related party, Zions Energy Corporation. The Zions Energy Corporation transaction was completed on the same terms as the unaffiliated investor transaction (see NOTE 16 RELATED PARTY TRANSACTIONS).

On May 16, 2012 and May 17,2012,the Company sold a 21.00% working interest in the Prescott Lease, including the requirement to participate in the RFO Prescott #25-6 Well located in the Koelsch Field and 229,800 warrants to purchase common stock at $2.50 per share for total cash of $619,500 to unaffiliated investors.

F-15

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

On May 31, 2012, the Company determined that a lease in the HUOP Freedom Trend Prospect was not valid as there were issues regarding the title of the property, no payments had been made and the lease term had expired. As a result, the lessor agreed to cancel the original amount owing by the Company on this lease in the amount of $180,000.

On June 28, 2012, the Company entered into an agreement (the “Skyline Oil Agreement”) with Skyline Oil, LLC (“Skyline Oil”), whereby the Company gave Skyline Oil (i) all of its interest in the Chad Wood Lease located in Central Utah; (ii) a 44.5% working interest in the Moroni #1-AXZH Well plus 320 surrounding acres; and (iii) a 15% working interest in 4,680 acres of the Independence Prospect, and in exchange Skyline Oil gave the Company (i) $1.6 million in cash; (ii) 200,000 shares of the Company’s common stock valued at $500,000 or $2.50 per share; and (iii) a 5% working interest in an additional 15,000 acres in a new Independence Prospect. The $500,000 from the return of 200,000 shares of common stock was treated as a return of capital and the remaining Independence Prospect unproved properties are now valued at $422,865. Following this transaction, the Company now owns a 5% working interest in 19,680 acres in the new Independence Prospect and a 5% working interest in the Moroni #1-AXZH Well plus 320 surrounding acres.

On June 30, 2012, the Company sold a 5.00% working interest with a 5.00% carried interest in a certain $800,000 work plan in the Perth Field that includes drilling one new well, three well recompletions, and work on a salt water disposal well to an unaffiliated investor for a value of $230,000. As consideration for this transaction, the investor agreed to reduce his note payable by $80,000 and exchanged a 50.00% working interest in a salt water disposal well that was valued at $150,000. This transaction was made in conjunction with the Company’s acquisition of 25.00% working interest in the Perth Field.

On October 1, 2012, the Company sold a 3.0625% working interest BPO and a 2.1875% working interest APO in the HPI Liberty #1 Well and Liberty Prospect from six unaffiliated investors for $192,500. In addition, the Company purchased a 12.95% working interest BPO and an 8.75% working interest APO in the HPI Liberty #1 Well, located in Juab County, Utah, from six unaffiliated investors for $630,000 which was paid by the issuance of 162,146 shares of common stock for a total value of $405,365, or $2.50 per share, plus the cancelation of $32,135 of JIBs accounts receivable owed to the Company by the investors.

On October 22, 2012, the Company transferred a 1.50% ORRI in the South Haven Field valued at $32,000 to an unaffiliated note holder, as consideration for prepaid interest on a $425,000 promissory note.

In December 2012, the Company sold a 1.00% working interest in the deep zones and a 1.00% working interest in the shallow zones in the HUOP Freedom Trend Prospect to an unaffiliated investor for a total value of $162,500. The purchase price was paid in $90,000 cash and a return to the Company of 29,000 shares of the Company’s common stock valued at $72,500, or $2.50 per share. The shares were returned to the Company and subsequently cancelled.

Divestitures for the year ended December 31, 2013

In March 2013, the Company sold a 20.0% working interest in the Wasatch National Forest #16-15 Well to two unaffiliated investors for a total of $145,626 with payments of $120,000 in cash and $25,626 through the return and cancelation of 25,626 shares of Common Stock valued at $1.00 per share.

In June 2013, the Company sold a 2.0% working interest in the Moroni #1 AXZH Well and in the surrounding 20,000 acres in the Independence Project for a total of $240,000, with payments of $220,000 in cash and $20,000 through the return and cancelation of 27,778 shares of Common Stock valued at $0.72 per share.

In July 2013, the Company sold a 2.0% ORRI in the Pine Springs/Edwin Prospect in the Central Utah Overthrust to an unaffiliated investor for $70,000 cash. As additional consideration for the sale, the Company granted warrants to purchase up to 70,000 shares of Common Stock with an exercise price of $1.00 that expire in July 2014.

F-16

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

In October 2013, the Company sold 51.25% working interest in the Wasatch National Forest #16-15 Well and the surrounding 640 acres to two unaffiliated investors for a total of $512,500 with payments of $112,500 in cash and $400,000 through the extinguishment of Notes Payable.

NOTE 5     NOTES PAYABLE

Notes Payable consists of the following:

	December 31,			December 31,
	2013			2012
Note Payable, interest at 12.0% per annum, monthly payments of $7,500, due October 2013,
secured by a 5.00% working interest in certain HUOP Freedom Trend Prospect leases.	$	-		$	750,000
Note Payable, interest at 10.0% per annum, monthly payments of $3,200, secured
by a 1.00% working interest in certain HUOP Freedom Trend Prospect leases.		-			366,709
Note Payable, interest at 7.5% per annum, monthly payments of $1,949, due January 2014,
secured by vehicle.		8,496			24,759
Note Payable, interest at 10.0% per annum, monthly payments of $15,000, due June 2014, secured
by a 10.00% working interest in certain HUOP Freedom Trend Prospect leases.		581,327			716,327
Note Payable, interest at 10.0% per annum, monthly payments of $5,000, secured
by a 1.00% working interest in certain HUOP Freedom Trend Prospect leases.		-			87,056
Note Payable, interest at 0.0% per annum, monthly payments of $1,500, due on demand, unsecured.		-			7,380
Note Payable, interest at 8.0% per annum, monthly payments of $10,000, due on demand, unsecured.		94,701			115,879
Note Payable, interest at 10.0% per annum, secured by certain new leases, rights,
and interests in the Central Utah Overthrust Project.		-			250,000
Note Payable, interest at 6.0% per annum, quarterly payments of $50,000, due January 2014, secured
by a 10.00% working interest in the Liberty Prospect.		389,000			589,000
Note Payable, interest at 0.0% per annum, unsecured.		-			190,000
Note Payable, interest at 0.0% per annum, due on demand, unsecured		15,000			-
Note Payable, interest at 10.0% per  annum, secured by a 1.00% working interest
in certain HUOP Freedom Trend Prospect leases.		-			65,000
Note Payable, interest at 12.0% per annum, due on demand, secured by a 10.00% working interest
in the Liberty Prospect.		50,000			-
Note Payable, interest at 8.0% per annum, due on demand, secured by a working interest
in certain Kansas leases.		100,000			-
Note Payable, interest at 8.0% per annum, due on demand, secured by a working interest
in certain Kansas leases.		100,000			-
Total Notes Payable		1,338,524			3,162,110
Less: Current Portion (includes demand notes)		(1,338,524	)		(1,487,419	)
Long-Term Portion	$	-		$	1,674,691

F-17

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

Estimated annual future maturities of Notes Payables are as follows:

Years Ended December 31,	Amount
2014	$	1,338,524
Thereafter		-
Total	$	1,338,524

NOTE 6     CONVERTIBLE NOTES PAYABLE

Convertible Notes Payable consists of the following:

	December 31,			December 31,
	2013			2012
Note Payable, interest at 12.0% per annum, due on demand, convertible into common shares of
the Company at a conversion rate of $2.50 per common share, unsecured.	$	52,560		$	52,560
Note Payable, interest at 10.0% per annum, due on demand, convertible into common shares of
the Company at a conversion rate of $2.50 per common share, secured by certain
Kansas Leases and 10.00% working interest in certain Fountain Green Project Leases (see
NOTE 19 LEGAL PROCEEDINGS).		369,090			1,300,000
Note Payable, interest at 10.0% per annum, due March 2014, convertible into common shares of
the Company at a conversion rate of $0.60 per common share subject to a ratchet adjustment provision
(see NOTE 12 COMMON STOCK), secured by a working interest in certain Kansas and Wyoming leases.		1,310,000			-
Note Payable, interest at 10.0% per annum, due March 2014, convertible into common shares of
the Company at a conversion rate of $0.60 per common share subject to a ratchet adjustment provision
(see NOTE 12 COMMON STOCK), unsecured.		150,000			-
Note Payable, interest at 12.0% per annum, due on demand, convertible into common shares of
the Company at a conversion rate determined by 50% of the weighted average price of the stock					-
during the five trading days immediately preceding the conversion date, secured by a 10.0% working
interest in the Liberty Prospect.		50,000
Note Payable, interest at 12.0% per annum, due on demand, convertible into common shares of
the Company at a conversion rate determined by 50% of the weighted average price of the stock					-
during the five trading days immediately preceding the conversion date, secured by a 10.0% working
interest in the Liberty Prospect.		50,000
Total Convertible Notes Payable		1,981,650			1,352,560
Less: Unamortized Debt Discount		(120,264	)		-
Less: Current Portion (includes demand notes)		(1,861,386	)		(1,352,560	)
Long-Term Portion	$	-		$	-

Estimated annual future maturities of Convertible Notes Payables are as follows:

Years Ended December 31,	Amount
2014	$	1,981,650
Thereafter		-
Total	$	1,981,650

F-18

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

NOTE 7    CAPITAL LEASE OBLIGATION

The Company leases certain well equipment under two capital lease agreements.  The term of the first capital lease was for 5 years with monthly payments in the amount of $3,200. The final payment on this lease was made in April 2013. The second lease is for a term of 10 months with monthly payments of $21,000. The final payment on this lease is due in June 2014.  As of December 31, 2013 and 2012, the remaining capital lease obligations were $135,311 and $15,748, respectively.

As of December 31, 2013 and 2012, total well equipment acquired under capital leases was $333,951 and $154,155 and accumulated depreciation was $139,165 and $106,440, respectively.

Estimated annual future maturities of capital leases are as follows:

Years Ended December 31,	Amount
2014	$	135,311
Thereafter		-
Total	$	135,311

NOTE 8     OPERATING LEASES

The Company leases office space in Salt Lake City, Utah (“Premises Lease”) which consists of approximately 5,482 square feet.  The Company entered into a five year and five month lease agreement effective September 1, 2013. The annualized lease obligations for the 12 month period September 1, 2013 to August 31, 2014 is $67,155 with annualized lease obligations for the subsequent 4 years in the amount of $115,122. The Company has a prepaid security deposit of $11,122.  For the years ended December 31, 2013 and 2012, the Premises Lease payments were $116,708 and $121,401, respectively.  

The Company leases a printer, copier and fax machine. The original lease term was for 37 months beginning in March 2010 with month lease payments of $255. The Company entered into a new 36 month lease with new equipment commencing January 2013 with monthly payments of $654. For the years ended December 31, 2013 and 2012 the lease payments were $8,250 and $3,060, respectively.

NOTE 9 OIL AND GAS PROPERTY LEASES

The following table sets forth the oil and gas property lease acreage with an expiration date within the next three years (December 31, 2016). The Company intends to renew or place into production all of these oil and gas property leases prior to their expiration.

	Acreage Expirations
Years Ended December 31,	Gross (1)		Net (2)
2014		5,820		5,192
2015		2,903		2,354
2016		80		72
Total		8,803		7,618

1- “Gross” means the total number of acres in which we have a working interest.

2- “Net” means the aggregate of the percentage working interests of the Company.

NOTE 10      ASSET RETIREMENT OBLIGATIONS

FASB ASC 410 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon the Company’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using the Company’s credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost.

F-19

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410 during the years ended December 31, 2013 and 2012:  

	December 31,
	2013			2012
Beginning asset retirement obligation	$	482,157		$	350,243
Liabilities incurred for new wells placed into production		17,294			140,876
Liabilities decreased for wells sold or plugged		(106,115	)		(14,409	)
Accretion of discount on asset retirement obligations		9,012			5,447
Revisions of previous estimates		39,727			-
Ending asset retirement obligations	$	442,075		$	482,157

NOTE 11 PREFERRED STOCK

As of December 31, 2013 and 2012, the Company had 50,000,000 shares of preferred stock authorized at a par value of $0.001 per share and had no shares of preferred stock issued or outstanding. The Company has 5,000,000 of the 50,000,000 shares of preferred stock authorized at a par value of $0.001 per share designated as “Series A Preferred Stock”.

On August 31, 2012, the Company filed a Certificate of Designation with the Nevada Secretary of State, designating 5,000,000 shares of the Company’s authorized shares of preferred stock as Series A Preferred Stock. All shares of common stock rank junior to the Series A Preferred Stock in regards to payment of dividends, liquidation, dissolution, and winding up of the Company.

The Series A Preferred Stock is convertible, at the option of the holders, into shares of common stock of the Company, at a per share conversion price determined by dividing the stated value of each share of Series A Preferred Stock by the average price at which shares of the Company’s common stock were sold over the 30-day period prior to the conversion, minus a 25.0% discount to such 30-day average price (the “Conversion Price”). Notwithstanding the foregoing, at no time shall the Conversion Price be less than $1.00 or greater than $3.70 per share.

The Company may redeem all or any portion of the Series A Preferred Stock at any time after August 31, 2014, or at any time if the Company’s common stock has traded at a rate of more than 10,000 shares per day for at least 30 consecutive days and the average trading price of the common stock (based on a 30-day moving average) is greater than $5.00 per share. The Series A Preferred Stock shall be redeemed by conversion into common stock of the Company. The Series A Preferred Stock redeemed shall be converted into shares of common stock of the Company at a per share conversion price determined by dividing the stated value of each share of Series A Preferred Stock by the Conversion Price. Notwithstanding the foregoing, at no time shall the Conversion Price used to determine the rate at which the Series A Preferred Stock shall be redeemed be less than $1.00 or greater than $3.70 per share. The holders of the Series A Preferred Stock shall have no voting rights, except as provided by Nevada law.

F-20

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

The holders of the Series A Preferred Stock shall be entitled to receive cumulative dividends on the Series A Preferred Stock at the rate of ten percent (10.0%) of the stated value per share per annum, payable quarterly.

As of September 30, 2012, the Company completed the sale of 285,000 units (the “Units”), each unit consisting of one share of Series A Preferred Stock, with a stated value of $1.00 per share and one warrant exercisable to acquire one-tenth of a share of the Company’s common stock at a price of $3.70 per share for a period of 3 years from the closing date, in exchange for gross proceeds of $285,000. The convertible preferred stock was recorded as a liability at the fair value of $380,000 in accordance with FASB ASC 480.

On December 19, 2012, the Company entered into letter agreements with the five unaffiliated holders of all 285,000 shares of the Company’s issued and outstanding Series A Preferred Stock (the “Preferred Shareholders”), each with a face value of $1.00 per share. Pursuant to the Letter Agreements, the Company and the Preferred Shareholders agreed to the conversion of all of the issued and outstanding Preferred Shares, along with all accrued dividends on the Preferred Shares through December 31, 2012, into shares of the Company’s common stock. The total amount of accrued dividends on the Preferred Shares through December 31, 2012 equals $9,515 (the “Dividends”) (see also NOTE 12 COMMON STOCK).

Notwithstanding the terms contained in the Company’s Certificate of Designation, filed on August 31, 2012 with the Nevada Secretary of State, relating to the conversion of the Preferred Shares, the Company and the Preferred Shareholders agreed to a conversion rate of $1.60 per share applicable to the conversion of the Series A Preferred Stock and the Dividends. The Series A Preferred Stock and the Dividends were converted at the $1.60 per share rate into 184,072 shares of the common stock. According to FASB ASC 480, upon issuance of the shares to settle the obligation of $380,000, equity is increased by the amount of the liability. Therefore, the value of the 184,072 shares issued was recorded at the fair value plus accrued interest amount for a total of $389,515 or $2.12 per share.

In consideration of the Preferred Shareholders’ conversion of the Series A Preferred Stock and the Dividends into the 184,072 shares of common stock, the Company agreed to use its commercially reasonable efforts to include the Conversion Shares in any registration by the Company of any of its securities, other than a registration relating solely to employee benefit plans, a registration relating to the offer and sale of debt securities, a registration relating to a corporate reorganization or other Rule 145 transaction, or a registration on any registration form that does not permit secondary sales.

NOTE 12     COMMON STOCK

Common Stock Issued During the Year Ended December 31, 2012

The Company issued 1,806,203 shares of common stock to unaffiliated investors for a value of $4,394,148 at a price between $1.60 and $2.50 per share. The issuance of these shares related to purchases of various working interests in oil and gas properties and cancelation of JIBs receivables.

The Company issued 282,511 shares of common stock to a related party for a value of $567,000 at a price between $1.60 and $2.50 per share. The issuance of these shares related to purchases of various working interests in oil and gas properties. (SEE NOTE 16 RELATED PARTY TRANSACTIONS).

The Company issued 1,443,378 shares of common stock to directors, employees, and consultants as compensation for services valued at $3,609,444 at a price between $1.50 and $2.50 per share. The shares issued were fully vested and the value of services was expensed on the day of grant. In addition, the Company granted warrants to purchase up to 650,000 shares of common stock to certain consultants. The warrants have an exercise price between $2.50 and $12.50 that vest over two years from April 2012 and June 2012 and expire between March 2015 and June 2015. The warrants were valued under the Black-Scholes valuation model based on factors that were present at the time the warrants were granted (see NOTE 13 WARRANTS TO PURCHASE COMMON STOCK). These warrants are being expensed over the two year vesting periods.

The Company issued 1,335,277 shares of common stock to unaffiliated investors for cash of $3,127,252 at a price between $1.60 and $2.50 per share. In addition, the company granted warrants to purchase up to 935,196 shares of common stock with an exercise price between $2.50 and $5.00 per share and expire between January 2013 and July 2015.

F-21

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

The Company issued 77,950 shares of common stock to an unaffiliated investor and a creditor for a value of $194,875 or $2.50 per share. These shares were issued as negotiated payments for settlement of outstanding obligations including accrued interest.

The Company issued 403,650 shares of common stock valued at $949,932 at a price between $1.60 and $2.50 per share to various noteholders pursuant to the exercising of their rights to convert certain notes payable and the prepayment of interest on a note payable.

The Company issued 7,193 shares of common stock to a related party, related to the exercise of warrants in settlement of interest outstanding on a note payable. The exercise price was $11,509 or $1.60 per share (see NOTE 16 RELATED PARTY TRANSACTIONS).

A former officer and director of the Company, voluntarily agreed to return to the Company, 25,000 shares of the Company’s common stock valued at $62,500 or $2.50 per share, to offset a portion of the independent audit fees recently incurred by the Company to complete the 2010 audit of Freedom, which was required by Rule 8-04 of Regulation S-X of the Exchange Act.

The Company received 229,000 shares of common stock from an entity and one of our shareholders valued at $572,500 or $2.50 as partial payment for the sale of certain working interests in oil and gas properties. The shares were returned to the Company and subsequently cancelled.

The Company issued 184,072 shares of common stock valued at $389,515 or $2.12 per share to five unaffiliated investors, relating to our redemption and conversion of all 285,000 shares of preferred stock that were outstanding, together with accrued preferred stock dividends totaling $9,515, at a conversion rate of $1.60 per share.

Unaffiliated investors and a related party assigned warrants to purchase 143,213 shares of our common stock to several unaffiliated investors and a related party for a total cash consideration of $28,642 or $0.20 per warrant. These warrants were then exercised to purchase 143,213 shares of our common stock for a total cash consideration of $229,141 or $1.60 per share (see NOTE 16 RELATED PARTY TRANSACTIONS).

Common Stock Issued During the Year Ended December 31, 2013

The Company issued 1,166,750 shares of common stock to unaffiliated investors and one director for cash of $1,069,000 at a price between $0.80 and $2.50 per share. In addition, the Company granted warrants to purchase up to 765,375 shares of common stock with an exercise price between $0.50 and $2.50 per share that expire between April 2013 and June 2014. Subsequent to the original issuance, warrants that were granted with an exercise price of $2.50 per share were repriced to $1.00 per share and warrants that expired in April 2013 were extended to December 2013 (see NOTE 13 WARRANTS TO PURCHASE COMMON STOCK and NOTE 16 RELATED PARTY TRANSACTIONS).

The Company issued 4,512,874 shares of common stock to unaffiliated debt holders at a negotiated and contract price between $0.12 and $2.50 per share for the extinguishment, reduction or settlement of notes payable, accrued interest, extension and conversion incentives, and issuance of new debt. The fair value of these shares at the time of issuance was $2,633,407. In addition, the Company granted warrants to purchase up to 3,044,853 shares of common stock with an exercise price at $1.00 that expire between April 2014 and December 2014.

The Company issued 10,000 shares of common stock at a negotiated price of $0.80 per share as partial consideration for the purchase of two leases in the HUOP Freedom Trend Project. The fair value of these shares at the time of purchase was $8,500.

The Company issued 1,102,064 shares of common stock at a negotiated settlement price between $0.80 and $2.50 per share to creditors, consultants, directors, officers and other employees as payment for outstanding payables. The fair value of the shares at the time of conversion was $889,832. In addition, the Company granted warrants to certain consultants to purchase up to 21,250 shares of common stock with an exercise price of $1.00 that expire in June 2014.

F-22

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

The Company issued 561,307 shares of common stock at a negotiated price between $0.25 and $2.50 per share to consultants and directors as compensation for services. The shares issued were fully vested and the fair value of the shares issued in the amount of $345,592 was expensed on the date of grant.

The Company issued 61,209 shares of common stock to two unaffiliated investors as the result of a ratchet provision on stock that was purchased for $5.00 per share that required the Company to issue additional shares of stock at no cost to the investor to make the effective price per share $2.50.

Two unaffiliated investors returned 25,626 shares of common stock, valued at $25,626, or $1.00 per share, and paid us $120,000 in cash to purchase a 20.00% working interest in our Wasatch National Forest #16-15 Well for a total value of $145,626. The shares were returned to the Company and subsequently cancelled.

The Company has 5,039,758 shares of common stock outstanding which were issued pursuant to written subscription agreements. As part of the agreements, a ratchet provision was included that in the event the Company sells shares of common stock or convertible securities at any time prior to December 31, 2013 at a price per share less than the respective subscription price of $0.60 to $0.80 per share, the Company contractually agrees to issue an additional amount of shares of common stock to make the effective price of the shares of common stock equal to the price per share of common stock that were sold for less than the subscription price.

These ratchet provisions are accounted for under the provisions of FASB ASC 815 which dictate the provisions to be accounted as embedded derivatives. These standards require the Company to determine the fair value of the ratchet provision and record a corresponding derivative liability in the financial statements. (See NOTE 17 FAIR VALUE). As of December 31, 2013, the Company is required to issue 816,200 shares of common stock under the terms of the ratchet provision. The Company issued shares of common stock pursuant to the ratchet provision in January 2014 (See NOTE 20 SUBSEQUENT EVENTS).

Treasury Stock

As of December 31, 2013 the Company had no shares of common stock held as treasury stock. During the year ended December 31, 2013 the Company acquired 25,626 shares of common stock valued at $25,626 or $1.00 per share. The Company retired all 25,626 shares during the year ended December 31 2013. During the year ended December 31, 2012 the Company acquired 254,000 shares of common stock valued at $635,000 or $2.50 per share. The Company retired all 254,000 shares during the year ended December 31, 2012. The Company accounts for treasury stock using the cost method.

NOTE 13     WARRANTS TO PURCHASE COMMON STOCK

As of December 31, 2013 and December 31, 2012, there were 5,361,587 and 2,166,874 warrants to purchase shares of common stock outstanding and fully vested, respectively. During the years ended December 31, 2013 and 2012, warrants totaling 4,451,478 and 2,037,497 for shares of common stock were granted.

During the year ended December 31, 2013, certain previously issued warrants with an exercise price between $1.00 and $5.00 and an expiration date between April 2013 and January 2014 were modified to an exercise price between $0.50 and $1.00 and an expiration date of June 2014. The fair value of the modification in the amount of $184,477 was expensed.

Of the total warrants granted during the year ended December 31, 2013, 765,375 warrants were granted in conjunction with private placements of common stock for cash proceeds (see NOTE 12 COMMON STOCK) that have an exercise price of between $0.50 and $2.50 per share and expire between December 2013 and June 2014.

F-23

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

Of the total warrants granted during the year ended December 31, 2012, 935,196 warrants were granted in conjunction with private placements of common stock for cash proceeds (see NOTE 12 COMMON STOCK) that have an exercise price between $2.50 and $5.00 per share and expire one to three years from the date of grant and 85,000 warrants were granted in conjunction with a debt settlement that have an exercise price of $2.50 per share and will expire one year from the date of grant.

The remaining 3,686,103 and 1,017,301 warrants granted during the years ended December 31, 2013 and 2012, respectively, were issued in conjunction with issuance and extinguishment of certain debt, payment for services, property purchased from the Company and issuance of preferred stock. These transactions are accounted for by the Company under the provisions of FASB ASC 470 and FASB ASC 505. These standards require the Company to record an expense associated with the fair value of stock-based payments.  The Company uses the Black-Scholes option valuation model to calculate the fair value of stock-based payments at the date of grant.  Warrant pricing models require the input of highly subjective assumptions, including the expected price volatility.  For warrants granted, the Company used a variety of comparable and peer companies as well as its own stock trading history to determine the expected volatility.  The Company believes that when its own stock trading history did not exist, the use of peer company data fairly represented the expected volatility it would experience if the Company were actively publicly traded in the oil and gas industry over the contractual term of the warrants. Changes in these assumptions can materially affect the fair value estimate. 

During the year ended December 31, 2013, the Company has determined the fair value of the 3,686,103 warrants granted to be $632,651, of which $617,276 has been expensed as of December 31, 2013. The remaining $15,375 will be expensed in future periods.

During the year ended December 31, 2012, the Company has determined the fair value of the 1,071,301 warrants granted to be $752,503, of which $448,096 has been expensed as of December 31, 2012. The remaining $304,407 is attributable to forfeited warrants and will not be expensed in future periods.

The following is the weighted average of the assumptions used in calculating the fair value of the warrants granted during the year using the Black-Scholes model:

	Years Ended December 31,
	2013			2012
Fair market value	$	0.63		$	2.46
Exercise price	$	1.00		$	5.83
Risk free rates		0.12	%		0.36	%
Dividend yield		0.00	%		0.00	%
Expected volatility		112.51	%		72.96	%
Contractual term		1.00 Year			2.89 Years
The weighted-average fair market value at the date of grant for warrants granted are as follows:
Fair value per warrant	$	0.1716		$	0.7397
Total warrants granted		3,686,103			1,017,301
Total fair value of warrants granted	$	632,651		$	752,503

							Weighted-
							Average
				Weighted			Remainder
				Average			Contractual
	Warrants			Exercise Price			Term in Year
As of December 31, 2012:
Warrants outstanding as of January 1, 2012		1,269,693		$	2.22			1.38
Granted		2,037,497		$	4.84			1.90
Exercised		(440,003	)	$	(1.60	)		-
Expired/Forfeited		(700,313	)	$	(7.14	)		-
Warrants outstanding as of December 31, 2012		2,166,874		$	3.22			1.32
As of December 31, 2013:
Warrants outstanding as of January 1, 2013		2,166,874		$	3.22			1.32
Granted		4,451,478		$	1.00			1.00
Exercised		-		$	-			-
Expired		(1,256,765	)	$	(2.13	)		-
Warrants outstanding as of December 31, 2013		5,361,587		$	1.27			0.63

F-24

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

NOTE 14     EMPLOYEE STOCK OPTIONS

In May 2013, the Company announced the appointment of Alan D. Gaines as Chairman of the Board of Directors and as part of his compensation package, the Company awarded Mr. Gaines 3,500,000 common stock options with an exercise price of $1.00 and which expire in May 2020. The options vest 50% upon the earlier of six months or the Company obtaining funding in excess of $3 million, 25% after one year and 25% after two years. The Company accounts for employee stock options according to FASB ASC 718 which requires the Company to calculate the fair value of the stock option on the date of grant and amortize over the vesting period of the options.

The following are the assumptions used in calculating the fair value of the options granted on May 6, 2013 using the Black-Scholes model:

Fair market value	$	0.90
Exercise price	$	1.00
Risk free rate		0.11	%
Dividend yield		0.00	%
Expected volatility		71.29	%
Expected life		4.08 Years

The Company used a variety of comparable and peer companies to determine the expected volatility.  The Company believes the use of peer company data fairly represents the expected volatility it would experience if the Company was more actively publicly traded in the oil and gas industry over the expected life of the options. The Company has no historical data regarding the expected life of the options and therefore used the simplified method of calculating the expected life. The risk free rate was calculated using the U.S. Treasury constant maturity rates similar to the expected life of the options, as published by the Federal Reserve. The Company has no plans to declare any future dividends.

The following table summarizes the Company’s total option activity for the year ended December 31, 2013:

	Options		Exercise Price		Remaining Term in Years
Options outstanding as of December 31, 2012		-		-		-
Granted		3,500,000	$	1.00		7.00
Exercised		-		-		-
Forfeited/Expired		-		-		-
Options outstanding as of December 31, 2013		3,500,000	$	1.00		6.35

Outstanding and exercisable stock options as of December 31, 2013 are as follows:

Options Outstanding					Options Exercisable
Number of Options Outstanding	Remaining Life (Years)		Exercise Price		Number of Options Exercisable	Exercise Price
3,500,000		6.35	$	1.00	1,750,000	$	1.00

F-25

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

The estimated fair value of the Company stock options, less expected forfeitures, is amortized over the options vesting period on the straight-line basis. The Company recognized the following equity-based compensation expenses during the year ended December 31, 2013:

	Year Ended
	December 31, 2013
Stock based compensation expense	$	795,009
Income tax benefit recognized related to stock-based compensation		-
Income tax benefit realized from the exercising and vesting of options		-

As of December 31, 2013, there was $795,009 of total unrecognized compensation cost with a remaining vesting period of 1.35 years.

As of December 31, 2013, the intrinsic value of outstanding and vested stock options was as follows:

	December 31, 2013
Intrinsic value – options outstanding	-
Intrinsic value – options exercisable	-
Intrinsic value – options exercised	-

NOTE 15     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, 2013 and 2012 consists of the following: 

	2013		2012
Current income taxes	$	1,567	$	400
Deferred income taxes		-		-
Provision for income taxes	$	1,567	$	400

The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2013 and 2012 to the amount of income tax expenses that would result from applying the statutory rate to pretax income.

Reconciliation of reported amount of income tax expense for the years ended December 31, 2013 and 2012 consists of the following:

	2013			2012
Income (Loss) before taxes and net operating loss	$	(6,798,017	)	$	(7,992,796	)
Federal statutory rate		@34	%		@34	%
Taxes (benefit) computed at federal statutory rates		(2,311,326	)		(2,717,550	)
State taxes (benefit), net of federal taxes		(224,334	)		(263,362	)
Effects of:
Share-based compensation		314,993			4,683,347
Other permanent differences		585,496			126,844
Freedom acquisition		-			567,707
Increase (decrease) in valuation allowance		1,636,738			(2,396,586	)
Reported Expense	$	1,567		$	400

F-26

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

At December 31, 2013 and 2012, the Company has net operating loss carry forwards for Federal income tax purposes of $28,725,339 and $22,546,058, respectively, which expire in varying amounts during the tax years 2017 through 2033. As a result of the Freedom acquisition in 2011 and the corresponding change in ownership, approximately $7,439,758 of the Company’s federal NOL’s are subject to a Section 382 limitation resulting in possible limitations on the future use of these net operating loss carry forwards.

The components of the Company’s deferred tax assets for the years ended December 31, 2013 and 2012 are as follows:

	2013			2012
Deferred tax assets
Current:
Accrued payroll	$	138,825		$	256,057
Current		138,825			256,057
Non-current:
Net operating loss carry forwards (NOLs)		10,714,551			8,409,680
Fixed assets		(257,081	)		(125,479	)
Oil & gas properties		(3,229,857	)		(2,939,716	)
Other		7,624			136,781
Non-current		7,235,237			5,481,266
Total deferred tax assets		7,374,062			5,737,323
Less: valuation allowance		(7,374,062	)		(5,737,323	)
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, 2013 and 2012. The change in the valuation allowance for the years ended December 31, 2013 and 2012 was $1,636,739 and ($2,396,586), 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, 2013 and 2012, 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, 2013, and 2012, 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, 2013 and 2012 relating to unrecognized tax benefits.

The tax years 2013, 2012, 2011, 2010, 2009 and 2008 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company is subject. In addition, due to the fact the Company merged with Freedom, Freedom’s tax returns, prior to the merger, for years 2004 to 2011 also remain open.

NOTE 16     RELATED PARTY TRANSACTIONS

Certain Relationships and Related Transactions

F-27

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

Each of the related-party transactions described below were reviewed and approved by a majority vote of the Board of Directors 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 the Board of Directors, such director abstained from voting to approve the transaction.

A. Douglas C. Hewitt, Sr., President, Chief Executive Officer and Director

Affiliates of Douglas C. Hewitt, Sr., our President and Chief Executive Officer and one of our Directors, have entered into a variety of transactions with Richfield as described below.

The D. Mack Trust

Mr. Hewitt is the sole beneficiary of The D. Mack Trust, an irrevocable trust established by Mr. Hewitt on May 15, 2009.

· As of March 31, 2014, the D. Mack Trust had ORRIs ranging from 0.50% to 3.625% in 1,636 net acres leased by Richfield in Kansas and Oklahoma, all of which were in place prior to January 1, 2012 or were purchased from MacKov in November 2012 (as described in further detail below).

The D. Mack Trust received $23,284 and $12,489 in royalties in 2013 and 2012, respectively, from the overriding royalty interests described above.

Mountain Home Petroleum Business Trust

Mr. Hewitt was a 33.4% beneficiary of, and a trustee of, the Mountain Home Petroleum Business Trust, a Utah business trust (“Mountain Home”) during the period beginning January 1, 2011 and ending December 31, 2012. On December 19, 2012, Mr. Hewitt resigned as a Trustee of Mountain Home and as of December 31, 2012, Mr. Hewitt was no longer a beneficiary of Mountain Home.

Prior to January 1, 2012, Mountain Home obtained the overriding royalty interests in conjunction with the establishment of the Utah Overthrust Agreement and the Liberty Prospect Agreement. No oil or natural gas has been extracted from the HUOP Freedom Trend Prospect or the HPI Liberty #1 Well and Liberty Prospect and therefore no royalties have been paid on those prospects.

Zions Energy Corporation

Zions Energy Corporation, a Utah corporation (“Zions”), is a wholly-owned subsidiary of Mountain Home and was affiliated with Mr. Hewitt by virtue of his beneficial interest in Mountain Home. Mr. Hewitt’s beneficial interest in Zions terminated concurrently with the termination of his affiliation with Mountain Home.

Richfield participated in the following transactions with Zions in 2012:

· In three transactions in February and March 2012, Richfield sold an aggregate of 1.00% working interest in the Moroni #1-AXZH Well and the 320 acres leasehold for total cash consideration of $77,561 to Zions. This purchase was made on the same terms as other third-party transactions that were completed in December 2011 and January 2012;

· In two transactions in February and March 2012, Richfield sold an aggregate of 3.00% working interest in the Koelsch Field, including the requirement to participate in the RFO Koelsch #25-1 Well, for total cash consideration of $9,090 to Zions. This purchase was made on the same terms as other third-party transactions that were completed in December 2011 and March 2012;

· In May 2012, Richfield received $50,000 in cash plus it acquired a 1.00% working interest in the Moroni #1-AXZH Well and the 320 acres leasehold from Zions in exchange for a 1.50% carried interest in the first well to be drilled in the shallow zone on the HUOP Freedom Trend Prospect. This exchange was made on the same terms as another third-party transaction that was completed in May 2012; and

· In August 2012, Zions loaned us $50,000 and we issued a Note Payable to Zions at 6.0% per annum, due September 30, 2012. In conjunction with the loan, we granted warrants to purchase 15,000 shares of our common stock, exercisable at $5.00 per share and expiring on September 29, 2013. The warrants were valued at $3.68 using the Black-Scholes option valuation model and were expensed on the date of grant. We repaid the note in September 2012, including $247 in interest.

F-28

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

During 2012, Zions received $4,662 in revenues from oil sales from our Koelsch Field.

B. Glenn G. MacNeil, Chief Financial Officer and  Director

Glenn G MacNeil, our Chief Financial Officer and one of our Directors, along with his spouse, owns 100% of the ownership interests in MacKov Investments Limited, an Ontario, Canada incorporated private company (“MacKov”).

Richfield participated in the following transactions with MacKov between January 1, 2012 and March 31, 2014:

· In November 2012, MacKov sold ORRIs ranging from 0.25% to 2.25% in 1,127 net acres of oil and natural gas properties located in Kansas to the D. Mack Trust and one unaffiliated investor;

· In February 2012, MacKov purchased a 1.50% working interest in the Koelsch Field from Richfield for cash of $4,545. In October 2012, MacKov sold all of its 5.00% working interest in the Koelsch Field to Richfield for $262,500. The consideration consisted of MacKov exercising 154,753 outstanding warrants to purchase 154,753 shares of our common stock valued at $247,605 or $1.60 per share and our issuance of 5,958 shares of our common stock valued at $14,895 or $2.50 per share. Each of these transactions were completed on the same terms as other independent third-party transactions in the Koelsch Field at or around the time of the transaction;

· In October 2012, MacKov sold all of its 1.00% carried working interest BPO and APO in the HPI Liberty #1 Well, its 1.00% working interest BPO and APO in the Liberty Prospect, its 2.25% working interest BPO and 1.75% working interest APO in the HPI Liberty #1 Well and Liberty Prospect to Richfield in exchange for 96,800 shares of common stock, valued at $242,000 or $2.50 per share. Each of these transactions were completed on the same terms as our other independent third-party transactions at or around the time of the transactions;

· In October 2012, MacKov sold all of its 0.50% working interest in the deep zones and its 0.25% working interest in the shallow zones of the HUOP Freedom Trend Prospect to Richfield in exchange for 25,000 shares of common stock, valued at $62,500 or $2.50 per share. Each of these transactions were completed on the same terms as our other independent third-party transactions at or around the time of the transaction;

· In February 2012, MacKov purchased a 0.50% working interest in the Moroni #1-AXZH Well and the 320 acre leasehold from Richfield for cash of $38,781. This purchase was made on the same terms as other independent third-party transactions in the Independence Field that were completed at or around the time of the transaction. On June 30, 2012, in connection with our sale to Skyline Oil, MacKov sold its 0.50% working interest in the Moroni #1-AXZH Well and the surrounding 320 acres to Skyline Oil;

· On June 30, 2012, MacKov settled a short term loan in the amount of $217,050 along with $82,172 of interest for a total of $299,222 for consideration consisting of a payment from Richfield to MacKov of $287,713 in cash and MacKov’s election to exercise warrants to purchase 7,193 shares of common stock at an exercise price of $11,509 or $1.60 per share. Each of these transactions were completed on the same terms as our other independent third-party loan transactions at or around the time of the transaction;

· In November 2012, MacKov granted a demand loan to Richfield in the amount of $65,000 with interest accruing at 10.0% per annum, secured by a 1% working interest in certain HUOP Freedom Trend Prospect leases (the “MacKov Demand Note”). On December 31, 2012, the Company paid all accrued interest under the MacKov Demand Note, in the amount of $727 and the principle was transferred to an independent third party.

As of December 31, 2013, MacKov has no working interests or ORRIs in oil or natural gas properties that we control or in which we own an interest and MacKov has no warrants outstanding to purchase our common stock.

F-29

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

For the years ended December 31, 2013 and 2012, MacKov received $0 and $12,642, respectively, in royalties relating to ORRIs and oil sales from working interest from Kansas leases including the Koelsch Field that were previously owned by MacKov.

C. Joseph P. Tate, a Director

Joseph P. Tate became one of our directors effective March 31, 2012. Mr. Tate has entered into the following transactions with Richfield between January 1, 2012 and December 31, 2013:

· 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 (See NOTE 20 SUBSEQUENT EVENTS for new lease agreement). 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;

· In March 2012, Mr. Tate and Richfield agreed to the repayment of a $100,000 outstanding payable, including interest of $18,000, through the issuance of 47,200 shares of common stock, valued at $118,000, or $2.50 per share.

· In October 2012, MacKov assigned warrants to purchase 88,057 shares of common stock to Joseph P. Tate and several unaffiliated investors for total cash consideration of $17,611, or $0.20 per warrant. Mr. Tate and the other unaffiliated investors then exercised the warrants to purchase 88,057 shares of common stock for total cash consideration of $140,889, or $1.60 per share.

· In May 2013, Mr. Tate purchased 250,000 shares of common stock of the Company for cash in the amount of $200,000, or $0.80 per share. The shares are subject to a ratchet provision that in the event the Company sells shares of common stock or convertible securities at any time prior to December 31, 2013 at a price per share less than $0.80, the Company shall issue an additional amount of shares of common stock to make the effective price of the shares of common stock equal to the price per share of common stock that were sold for less than $0.80. In addition, the Company granted warrants to Mr. Tate to purchase up to 125,000 shares of common stock with an exercise price of $1.00 that expire in May 2014. In January 2014, 262,821 shares of common stock were issued pursuant to the terms of this provision.

D. Alan D. Gaines, Chairman of the Board

Alan D. Gaines, Chairman of the Board of Directors, is a party to the following transaction with the Company between January 1, 2012 and December 31, 2013:

· In May 2013, the Company announced the appointment of Alan D. Gaines as Chairman of the Board of Directors and as part of his compensation package, the Company awarded Mr. Gaines 3,500,000 common stock options with an exercise price of $1.00 and expire in May 2020. The options vest 50% upon the earlier of six months or the Company obtaining funding in excess of $3 million, 25% after one year and 25% after two years. In January 2014, the options were cancelled and 4,908,532 shares of common stock were issued at value of $1,472,560 or $0.30 per share (See NOTE 20 SUBSEQUENT EVENTS).

NOTE 17     FAIR VALUE

FASB ASC 820 defines fair value, establishes a framework for measuring fair value under U.S. generally accepted accounting principles and enhances disclosures about fair value measurements.  Fair value is defined under FASB ASC 820 as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.  Valuation techniques used to measure fair value under FASB ASC 820 must maximize the use of observable inputs and minimize the use of unobservable inputs.  The standard describes a fair value hierarchy based on three levels of inputs, with the first two inputs considered observable and the last input considered unobservable, that may be used to measure fair value as follows:

F-30

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

· Level one — Quoted market prices in active markets for identical assets or liabilities;

· Level two — Inputs other than level one inputs that are either directly or indirectly observable; and

· Level three — Unobservable inputs developed using estimates and assumptions, which are developed by the reporting entity and reflect those assumptions that a market participant would use.

Determining which category an asset or liability falls within the hierarchy requires significant judgment. The Company evaluates its hierarchy disclosures each quarter. The Company has two liabilities measured at fair value, the Company’s asset retirement obligation (See NOTE 10 ASSET RETIREMENT OBLIGATIONS) and a derivative liability in connection with a ratchet provision on certain issuances of the Company’s common stock (see NOTE 12 COMMON STOCK). The Company has no assets that are measured at fair value.

The fair value of the Company’s asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. These estimates are derived from historical costs as well as management’s expectation of future costs environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in NOTE 10 ASSET RETIREMENT OBLIGATIONS.

The fair value of the Company’s derivative liability was determined using estimates and assumptions that are not readily available in public markets and has designated this liability as Level 3. As of December 31, 2013 the derivative liability had an estimated fair value of $310,156. The following table presents a reconciliation of the beginning and ending balances of our derivative liability, as of December 31, 2013:

Balance at December 31, 2012	$	-
New Derivative Liability		1,066,932
Transfers to (from) Level 3		-
Total (gains)/losses included in earnings		(756,776	)
Issuances		-
Balance at December 31, 2013	$	310,156

NOTE 18     FINANCIAL INSTRUMENTS AND CONCENTRATION RISKS

The Company’s financial instruments include cash and cash equivalents, accounts receivable and accounts payable. The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value because of their immediate or short-term maturities.

Substantially all of the Company’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and gas industry.  This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. As of December 31, 2013, 70% of the accounts receivable balance resulted from three entities.  As of December 31, 2012, 71% of the accounts receivable balances were resulted from two entities.  Historically, the Company has not experienced significant credit losses on such receivables.  There was no bad debt recorded against accounts receivable for the years ended December 31, 2013 and 2012.  The Company cannot ensure that such losses will not be realized in the future.  For the years ended December 31, 2013 and 2012 the percentage of revenues resulting from producing wells in Kansas was 99% and 100%, respectively.

F-31

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

NOTE 19 LEGAL PROCEEDINGS

On February 1, 2012, Nostra Terra Oil & Gas Company (“NTOG”) filed an action against Richfield, Hewitt Petroleum, Inc., Hewitt Energy Group, Inc., and Hewitt Energy Group, LLC in the Twenty-Third Judicial District Court of Russell County, Kansas. The complaint alleges that we defaulted on our repayment obligations under a note and security agreement, dated April 13, 2011, in the principal amount of $1,300,000 and accrued interest at 10% per annum. During 2013 the Company made substantial payments towards the payment of the obligation. On February 14, 2014 the Court entered a final judgment in favor of Nostra Terra Oil and Gas Company and against Richfield Oil & Gas Company and Hewitt Energy Group, Inc. in the sum of $220,849. The Company is in the process of paying the judgment.

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 $50,386 plus interest. The Company believes that this claim was paid in full in September 2011 and plans on vigorously defending the action.

In February 2014, the Company became aware that on June 6, 2012, United States Fidelity and Guaranty Company filed an action against Douglas C. Hewitt based upon a liability as a guarantor of a plugging bond posted with the Oklahoma Corporation Commission. The Oklahoma Corporation Commission claimed the Bond for plugging a well previously owned by HEGCO Canada and Hewitt Energy Group LLC. Hewitt Petroleum, Inc., the predecessor in interest to Richfield Oil & Gas Company, purchased the assets of Hewitt Energy in January 2009. Pursuant to that purchase Hewitt Petroleum agreed to indemnify Douglas C. Hewitt. The Bond was guaranteed by HEGCO Canada Inc, which has been discharged in Bankruptcy, Douglas C. Hewitt, J. David Gowdy, Rodney Babb, and Nemaha Services. The Company is seeking contribution towards the judgment from Rodney Babb and Nemaha Services. As of March 17, 2014 the Company has paid $1,500 towards the obligation. The total obligation is $30,754.

At a hearing with the Kansas Corporation Commission (“KCC”) on November 21, 2013 the KCC imposed a $10,000 fine against Hewitt Energy Group, Inc., for the failure to bring certain wells into KCC compliance pursuant to an order issued in August 2012. The Company had brought 16 of 23 wells into KCC compliance as of November 21, 2013. At the November 21, 2013 KCC hearing Hewitt Energy Group, Inc., was provided three weeks per well to finalize the last seven wells to be brought into compliance. In February 2014 Hewitt Energy Group, Inc. was granted an additional three weeks due to local weather conditions. As of March 31, 2014 Hewitt Energy Group Inc. has brought four of the last seven wells into compliance. The remaining three wells are required to be completed by May 23, 2014. If the wells are not in compliance by May 23, 2014, Hewitt Energy Group’s operating license may be suspended until the wells are in compliance and Hewitt Energy Group may be fined. The Company is currently working to bring the last three wells into KCC compliance.

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.

F-32

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

NOTE 20     SUBSEQUENT EVENTS

In January 2014, The Company issued 3,969,408 shares of common stock to unaffiliated investors and one director pursuant to a ratchet provision on stock that was previously issued with written subscription agreements (see NOTE 12 COMMON STOCK).The ratchet provision expired on December 31, 2013 with the terms of the provision requiring 816,200 shares of common stock be issued to make the effective price of the original issuances of stock equal to $0.60 per share. However, in January 2014, the Company determined to issue 3,153,208 additional shares to make the effective price of the original issuances of stock equal to $0.39 per share.

In January 2014, The Board of Directors approved the cancellation of 3,500,000 outstanding employee stock options issued to Mr. Alan D. Gaines, our Executive Chairman of the Board of Directors (see NOTE 14 EMPLOYEE STOCK OPTIONS) and the issuance to him of 4,908,532 restricted Company common stock representing 9.9% of the Company’s common shares at the time. The stock was fully vested and the fair value of the shares issued in the amount of $1,472,560 or $0.30 per share was expensed on the date of grant.

In January 2014, the Company issued 200,000 shares of common stock to a director for cash of $50,000 at a price of $0.25 per share. In addition, the Company granted warrants to purchase up to 200,000 shares of common stock with an exercise price of $0.25 per share that expire in July 2014.

In January 2014, The Company consolidated notes payable and other short term advances from and unaffiliated investor in the amount of $2,665,747 into a convertible line of credit with interest at 12% per annum and due on June 30, 2014. Since January 2014, additional advances in the amount of $314,744 have been received.

In January and March 2014, the Company issued 888,598 shares of common stock to unaffiliated debt holders at a contract price between $0.12 and $0.13 per share for the conversion of notes payable, accrued interest, and conversion incentives. The fair value of these shares at the time of issuance was $196,614 or between $0.21 and $0.25 per share.

In February and March 2014, the Company issued 669,167 shares of common stock to consultants as compensation for services. The shares issued were fully vested and the fair value of the shares issued in the amount of $166,799 or between $0.22 and $0.26 per share was expensed on the date of grant.

In March 2014, the Company issued 1,300,000 shares of common stock to unaffiliated investors pursuant to a joint venture agreement to finish the completion of the HPI Liberty #1 Well in the Liberty Prospect. The shares issued were fully vested and the fair value of the shares at the time of issuance was $276,380 or $0.21 per share. In addition, the Company granted warrants to purchase up to 1,300,000 shares of common stock with an exercise price of $0.25 that expire in August 2014.

In March 2014, the Company issued 280,000 shares of common stock to a consultant for a value of $64,400 or $0.23 per share. These shares were issued as a negotiated payment for settlement of an outstanding payable.

In March 2014, the Company issued warrants to purchase up to 600,000 shares of common stock to an existing debt holder as consideration to extend the due date of a note payable to December 31, 2014. The exercise price of the warrants is $0.25 and they expire in March 2015.

In March 2014, the Company consolidated and replaced two expiring oil and gas leases with Joseph P. Tate, a director, and Jenifer M. Tate as Joint Tenants (see NOTE 16 RELATED PARTY TRANSACTIONS), covering a combined 1,823 gross acres in the HUOP Freedom Trend Prospect. The initial bonus for the new lease totals $182,308 and represents a prepayment of all delay rentals for the 10 year primary term commencing April 15, 2014. The initial bonus amount is similar to third party 10 year primary term leases obtained by the company in the HUOP Freedom Trend Prospect during 2013.

F-33

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

NOTE 21     SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves and Related Financial Data

Information with respect to the Company's crude oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Pinnacle Energy Services L.L.C. as of December 31, 2013 and 2012, an independent petroleum consultant based on information provided by the Company.

The following table sets forth the aggregate capitalized costs related to oil and natural gas producing activities at December 31, 2013 and 2012.

	2013			2012
Unproved Oil and Gas Properties	$	14,095,020		$	14,164,053
Proved Oil and Gas Properties	$	7,139,663		$	6,581,725
Well and Related Equipment	$	1,997,913		$	1,024,972
Accumulated Depreciation, Depletion, and Amortization, and Valuation Allowances	$	(1,224,523	)	$	(923,083	)
Net Capitalized Costs	$	22,008,073		$	20,847,667

The following table sets forth the costs incurred in oil and gas property acquisition, exploration and development activities for the years ended December 31, 2013 and 2012.

	2013		2012
Acquisition of Properties
Proved	$	-	$	2,033,125
Unproved	$	297,773	$	4,368,860
Exploration Costs	$	200,244	$	764,417
Development Costs	$	2,149,872	$	1,849,445

The following tables present the Company's independent petroleum consultant’s estimates of our proved oil and natural gas reserves, as of December 31, 2013 and 2012. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

	Oil (Bbl)			Natural Gas (Mcf)
Net Proved Developed and Undeveloped Reserves at December 31, 2011		675,630			267,400
Revisions of Previous Estimates		572,988			207,369
Improved Recovery		-			-
Purchase of Reserves in Place		254,691			15,760
Extensions, Discoveries and Other Additions		96,440			46,771
Net Production		(10,931	)		-
Sale of Reserves in Place		(20,628	)		(9,990	)
Net Proved Developed and Undeveloped Reserves at December 31, 2012		1,568,190			527,310
Revisions of Previous Estimates		(50,222	)		(2,310	)
Improved Recovery		-			-
Purchase of Reserves in Place		-			-
Extensions, Discoveries and Other Additions		57,508			-
Net Production		(11,331	)		-
Sale of Reserves in Place		(223,145	)		-
Net Proved Developed and Undeveloped Reserves at December 31, 2013		1,341,000			525,000

During 2013, several factors impacted our total Net Proved Developed and Undeveloped Reserves by the following:

F-34

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

· We modified the adjusted economic prices from $2.068/MCF for natural gas and $91.05/Bbl for oil in the Perth and South Haven Fields, $88.45/Bbl for oil in all other Kansas properties, and $84.90/Bbl for oil in the Wyoming properties used in our Reserves and Engineering Evaluation, dated January 18, 2013 (our “2012 Pinnacle Reserve Report”), to $2.75/MCF for natural gas and $93.28/Bbl for oil in the Perth and South Haven Fields, $90.68/Bbl for oil in all other Kansas properties, and $87.13/Bbl for oil in the Wyoming properties used in the 2013 Pinnacle Reserve Report. The pricing revisions caused our Net Proved Developed and Undeveloped Reserves to increase by 47 oil MBbls and to increase by 143 natural gas MMcf.

· We increased the lease operating expenses for our development plan to reflect our historical cost levels which resulted in our Net Proved Developed and Undeveloped Reserves to decrease by 51 oil MBbls and a decrease by 145 natural gas MMcf.

· We made changes to our two-year development plan, including adding seven new well locations which increased our Net Proved Developed and Undeveloped Reserves by 92 oil MBbls and 33 natural gas MMcf; removing four well locations from our new two-year development plan which decreased our reserves by 51 oil MBbls and 18 natural gas MMcf; and three well locations being moved to probable which decreased our reserves by 88 oil MBbls and 15 natural gas MMcf for a total net decrease of 47 oil MBbls and an decrease of 0 natural gas MMcf.

· We sold a 60% working interest in the Graham Reservoir Field in Uinta County, Wyoming, which had reserves in place. This sale caused our Net Proved Developed and Undeveloped Reserves to decrease by 233 oil MBbls and by 0 natural gas MMcf.

· We did recompletion work on an existing wellbore in the South Haven Field to increase Net Proved Developed and Undeveloped Reserves by 57 oil MBbls and 0 natural gas MMcf, through conversion of Probable Reserves into Net Proved Developed and Undeveloped Reserves.

· Our actual production resulted in a decrease in our total Net Proved Developed and Undeveloped Reserves of 11 oil MBbls. There was no natural gas production.

	Oil (Bbl)		Natural Gas (MCF)
Proved Developed Reserves
Beginning of year 2012		106,060		-
End of year 2012		546,560		118,620
Beginning of year 2013		546,560		118,620
End of year 2013		472,000		103,000
Proved Undeveloped Reserves
Beginning of year 2012		569,570		267,400
End of year 2012		1,021,630		408,690
Beginning of year 2013		1,021,630		408,690
End of year 2013		869,000		421,000

Proved reserves are estimated quantities of oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years.

Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein

F-35

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

The following table presents a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas were prepared in accordance with the provisions of ASC 932-235-50. Future cash inflows were computed by applying oil and natural gas prices that were calculated by using the unweighted arithmetic average of the first-day-of-the-month price for each month of the 12-month period prior to the ending date of the period, to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year-end tax rates to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carry forwards relating to oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company's oil and natural gas reserves.

Standardized Measure of Discounted Future Net Cash Flows at December 31, 2013 and 2012
	2013			2012
Future Cash Inflows	$	124,095,840		$	140,043,710
Future Development Costs		(22,309,810	)		(26,062,540	)
Future Production Costs		(56,390,950	)		(59,329,510	)
Future Income Tax Expenses		(16,932,365	)		(20,385,069	)
Future Net Cash Flows	$	28,462.715		$	34,266,591
10% Annual Discount for Estimated Timing of Cash Flows		(10,356,209	)		(12,994,274	)
Standardized Measure of Discounted Future Net Cash Flows	$	18,106,506		$	21,272,317

The following table presents the aggregate change in the standardized measure of discounted future net cash flows for the years ended December 31, 2013 and 2012.

Changes in the Standardized Measure of Discounted Cash Flows for the Years Ended December 31, 2013 and 2012
	2013			2012
Net Change in Sales and Transfer Prices and in Production (Lifting) Costs Related to Future Production	$	(4,699,746	)	$	15,115,402
Changes in Estimated Future Development Costs		3,752,730			(13,914,960	)
Sales and Transfers of Oil and Gas Produced During the Period		(774,426	)		(952,566	)
Net Change Due to Extensions, Discoveries, and Improved Recovery		1,565,304			3,104,457
Net Change Due to Purchases and Sales of Reserves in Place		(5,935,737	)		5,341,555
Net Change Due to Revisions in Quantity Estimates		(2,164,844	)		11,736,779
Previously Estimated Development Costs Incurred During the Period		2,042,378			1,730,765
Accretion of Discount		(404,174	)		(186,278	)
Other – Unspecified		-			-
Net Change in Income Taxes		3,452,704			(10,506,966	)
Aggregate Change in the Standardized Measure of Discounted Future Net Cash Flows for the Year	$	(3,165,811	)	$	11,468,188

During 2013, there were several factors that affected our Aggregate Change in the Standardized Measure of the Discounted Future Net Cash Flows for the Year. Net Change in Sales and Transfer Prices and in Production (Lifting) Costs Related to Future Production from December 31, 2013 and 2012 are represented by the change in the economic prices and lease operating expenses used in our engineering reports. We modified the adjusted economic prices from $2.068/MCF for natural gas and $91.05/Bbl for oil in the Perth and South Haven Fields, $88.45/Bbl for oil in all other Kansas properties, and $84.90/Bbl for oil in the Wyoming properties used in our Reserves and Engineering Evaluation, dated January 18, 2013 (our “2012 Pinnacle Reserve Report”), to $2.75/MCF for natural gas and $93.28/Bbl for oil in the Perth and South Haven Fields, $90.68/Bbl for oil in all other Kansas properties, and $87.13/Bbl for oil in the Wyoming properties used in the 2013 Pinnacle Reserve Report. In addition, we increased the lease operating expenses to reflect our historical cost levels. Net Change Due to Revisions in Quantity Estimates, and Changes in Estimated Future Development Costs, were affected by a change in our work plan. We made changes to our two-year development plan, including adding seven new well locations, removing four well locations and moved three well locations from proved to probable. Net Change Due to Purchases and Sales of Reserves in Place was affected by the sale of working interest in one property. In addition to these, there were changes in our Standardized Measure of the Discounted Future Net Cash Flow because of our actual development costs and production for the year and associated changes in Income Taxes, Accretion of Discount.

F-36

RICHFIELD OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

Oil and natural gas prices were calculated by using the unweighted arithmetic average of the first-day-of-the-month price for each month of the 12-month period prior to the ending date of the period, and were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company's reserves. The prices for the Company's reserve estimates were as follows:

	Natural Gas MCF		Oil Bbl
December 31, 2012:
South Haven, Perth and Oklahoma Properties	$	2.068	$	91.05
All Other Kansas Properties	$	2.068	$	88.45
Wyoming Properties	$	2.068	$	84.90
December 31, 2013:
South Haven and Perth Properties	$	2.75	$	93.28
All Other Kansas Properties	$	2.75	$	90.68
Wyoming Properties	$	2.75	$	87.13

F-37

Exhibit Index

Exhibit
Number	Description
2.1	Letter Agreement, dated March 4, 2011, between Freedom Oil & Gas, Inc. and Hewitt Petroleum, Inc. (incorporated by reference to Exhibit 2.1 to our registration statement on Form 10-12G filed on December 30, 2011).
2.2	Closing Agreement, dated March 31, 2011, between Freedom Oil & Gas, Inc. and Hewitt Petroleum, Inc. (incorporated by reference to Exhibit 2.2 to our registration statement on Form 10-12G filed on December 30, 2011).
2.3**	Agreement and Plan of Merger between Hewitt Petroleum, Inc. and Richfield Oil & Gas Company, dated March 31, 2011 (incorporated by reference to Exhibit 2.3 to our registration statement on Form 10-12G filed on December 30, 2011).
2.4	Articles of Merger, dated June 16, 2011, by and between Richfield Oil & Gas Company and Freedom Oil & Gas, Inc. (incorporated by reference to Exhibit 2.4 to our registration statement on Form 10-12G filed on December 30, 2011).
3.1	Articles of Incorporation of Richfield Oil & Gas Company, dated March 31, 2011 (incorporated by reference to Exhibit 3.1 to our registration statement on Form 10-12G filed on December 30, 2011).
3.2	Certificate of Amendment of Articles of Incorporation of Richfield Oil & Gas Company, dated October 22, 2012 (incorporated by reference to Exhibit 3.1 to our current report on Form 8-K filed on October 25, 2012).
3.3	Certificate of Designation (incorporated by reference to Exhibit 3.1 to our current report on Form 8-K filed on September 10, 2012).
3.4	Amended and Restated By-laws of Richfield Oil & Gas Company, dated April 8, 2011 (incorporated by reference to Exhibit 3.2 to our registration statement on Form 10-12G filed on December 30, 2011).
4.1	Form of Subscription Agreement (including warrant to purchase shares at $0.25 per share) (incorporated by reference to Exhibit 4.1 to our registration statement on Form 10-12G filed on December 30, 2011).
4.2	Form of Subscription Agreement (including warrant to purchase shares at $0.30 per share) (incorporated by reference to Exhibit 4.2 to our registration statement on Form 10-12G filed on December 30, 2011).
4.3	Warrant to Purchase 6,000,000 Shares of Common Stock, Par Value $0.001 Per Share, dated April 13, 2011, granted by Richfield Oil & Gas Company to Nostra Terra Oil & Gas Company, PLC (incorporated by reference to Exhibit 4.3 to our registration statement on Form 10-12G filed on December 30, 2011).
4.4	Convertible Promissory Note, dated February 2, 2009, between Freedom Oil & Gas, Inc. and Quantum Energy & Technologies, LLC (incorporated by reference to Exhibit 4.4 to our registration statement on Form 10-12G filed on December 30, 2011).
4.5	Extension and Restatement of Convertible Promissory Notes, dated March 31, 2011, between Freedom Oil & Gas, Inc. and Quantum Energy & Technologies, LLC (incorporated by reference to Exhibit 4.5 to our registration statement on Form 10-12G filed on December 30, 2011).

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4.6	Amendment to Extension and Restatement of Convertible Promissory Notes, dated July 20, 2011, between Freedom Oil & Gas, Inc. and Quantum Energy & Technologies, LLC (incorporated by reference to Exhibit 4.6 to our registration statement on Form 10-12G filed on December 30, 2011).
4.7	Second Amendment to Extension and Restatement of Convertible Promissory Notes, dated September 30, 2011, between Richfield Oil & Gas Company and Quantum Energy & Technologies, LLC (incorporated by reference to Exhibit 4.7 to our registration statement on Form 10-12G filed on December 30, 2011).
4.8	Convertible Promissory Note, dated April 13, 2011, among Hewitt Petroleum, Inc., Hewitt Energy Group, Inc. and Nostra Terra Oil & Gas Company, PLC (incorporated by reference to Exhibit 4.8 to our registration statement on Form 10-12G filed on December 30, 2011).
4.9	Convertible Promissory Note, dated April 29, 2011, between Richfield Oil & Gas Company and MacKov Investments Limited (incorporated by reference to Exhibit 4.9 to our registration statement on Form 10-12G filed on December 30, 2011).
4.10	Amendment to Convertible Promissory Note, dated June 3, 2011, between Richfield Oil & Gas Company and MacKov Investments Limited (incorporated by reference to Exhibit 4.10 to our registration statement on Form 10-12G filed on December 30, 2011).
4.11	Convertible Promissory Note, dated June 14, 2011, between Richfield Oil & Gas Company, MacKov Investments Limited and Peter Lazarevski (incorporated by reference to Exhibit 4.11 to our registration statement on Form 10-12G filed on December 30, 2011).

4.12	Amendment to Convertible Promissory Note, dated June 28, 2011, between Richfield Oil & Gas Company, MacKov Investments Limited and Peter Lazarevski (incorporated by reference to Exhibit 4.12 to our registration statement on Form 10-12G filed on December 30, 2011).
4.13	Second Amendment to Convertible Promissory Note, dated July 18, 2011, between Richfield Oil & Gas Company, MacKov Investments Limited and Peter Lazarevski (incorporated by reference to Exhibit 4.13 to our registration statement on Form 10-12G filed on December 30, 2011).
4.14	Third Amendment to Promissory Note, dated September 28, 2011, between Richfield Oil & Gas Company, MacKov Investments Limited and Peter Lazarevski (incorporated by reference to Exhibit 4.14 to our registration statement on Form 10-12G filed on December 30, 2011).
4.15	Replacement Promissory Note, dated October 20, 2011, between Richfield Oil & Gas Company and MacKov Investments Limited (incorporated by reference to Exhibit 4.15 to our registration statement on Form 10-12G filed on December 30, 2011).
4.16	Promissory Note, dated August 12, 2010, between Hewitt Petroleum, Inc. and Jupiter LP (incorporated by reference to Exhibit 4.16 to our registration statement on Form 10-12G filed on December 30, 2011).
4.17	Amended Promissory Note, dated August 12, 2010, between Hewitt Petroleum, Inc. and Scott West (incorporated by reference to Exhibit 4.17 to our registration statement on Form 10-12G filed on December 30, 2011).
4.18	Lease Financing Agreement, dated October 22, 2010, between Hewitt Petroleum, Inc. and Jupiter LP (incorporated by reference to Exhibit 4.18 to our registration statement on Form 10-12G filed on December 30, 2011).
4.19	Amendment to Convertible Promissory Notes, dated December 15, 2011, between Richfield Oil & Gas Company and Jupiter LP (incorporated by reference to Exhibit 4.19 to our registration statement on Form 10-12G filed on December 30, 2011).
4.20	Promissory Note, dated August 12, 2010, between Hewitt Petroleum, Inc. and Sally West (incorporated by reference to Exhibit 4.20 to our registration statement on Form 10-12G filed on December 30, 2011).

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4.21	Convertible Promissory Note, dated July 15, 2011, between Richfield Oil & Gas Company and Bruce Bent (incorporated by reference to Exhibit 4.21 to our registration statement on Form 10-12G filed on December 30, 2011).
4.22	Convertible Promissory Note, dated July 15, 2011, between Richfield Oil & Gas Company and Randy Pilon (incorporated by reference to Exhibit 4.22 to our registration statement on Form 10-12G filed on December 30, 2011).
4.23	Convertible Promissory Note, dated October 11, 2007, between Freedom Oil & Gas, Inc. and David R. Brallier and/or Cheryl P. Brallier, Trustees of the Revocable Trust of David R. Brallier (incorporated by reference to Exhibit 4.23 to our registration statement on Form 10-12G filed on December 30, 2011).
4.24	Amendment to Restated Convertible Promissory Note, dated March 24, 2011, between Freedom Oil & Gas, Inc. and David R. Brallier and/or Cheryl P. Brallier, Trustees of the Revocable Trust of David R. Brallier (incorporated by reference to Exhibit 4.24 to our registration statement on Form 10-12G filed on December 30, 2011).
4.25	Amendment to Restated Convertible Promissory Note, dated December 15, 2011, between Richfield Oil & Gas Company and David R. Brallier and/or Cheryl P. Brallier, Trustees of the Revocable Trust of David R. Brallier (incorporated by reference to Exhibit 4.25 to our registration statement on Form 10-12G filed on December 30, 2011).
4.26	Form of Common Stock Certificate of Richfield Oil & Gas Company (incorporated by reference to Exhibit 4.26 to our registration statement on Form 10-12G filed on December 30, 2011).
4.27	Form of Subscription Agreement (including warrant to purchase shares at $0.50 per share) (incorporated by reference to Exhibit 4.27 to our registration statement on Form 10-12G/A filed on August 17, 2012).
10.1	Operating Agreement, Liberty # 1 Well, Liberty Prospect, dated March 25, 2010, between Hewitt Operating, Inc., as Operator, and the signatory parties thereto, as Non-Operators (incorporated by reference to Exhibit 10.1 to our registration statement on Form 10-12G filed on December 30, 2011).
10.2	Letter Agreement, dated January 26, 2011, between Freedom Oil & Gas, Inc. and Skyline Oil, LLC (incorporated by reference to Exhibit 10.2 to our registration statement on Form 10-12G filed on December 30, 2011).
10.3	Letter Agreement, dated August 31, 2011, between Richfield Oil & Gas Company and Skyline Oil, LLC (incorporated by reference to Exhibit 10.3 to our registration statement on Form 10-12G filed on December 30, 2011).
10.4×	Letter Agreement, dated March 4, 2011, between Hewitt Petroleum, Inc. and Glenn MacNeil (incorporated by reference to Exhibit 10.5 to our registration statement on Form 10-12G filed on December 30, 2011).
10.5×	Letter Agreement re Stock Reconciliation, dated March 28, 2011, between Hewitt Petroleum, Inc. and MacKov Investments Limited (incorporated by reference to Exhibit 10.6 to our registration statement on Form 10-12G filed on December 30, 2011).
10.6×	Letter Agreement re Purchase of Overriding Royalty Interest, dated March 28, 2011, between Hewitt Petroleum, Inc. and MacKov Investments Limited (incorporated by reference to Exhibit 10.7 to our registration statement on Form 10-12G filed on December 30, 2011).

10.7× Financial Services Agreement, dated April 1, 2011, between Hewitt Petroleum, Inc. and MacKov Investments Limited (incorporated by reference to Exhibit 10.8 to our registration statement on Form 10-12G filed on December 30, 2011).

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10.8×	Promissory Note, dated September 7, 2011, between Richfield Oil & Gas Company and MacKov Investments Limited (incorporated by reference to Exhibit 10.9 to our registration statement on Form 10-12G filed on December 30, 2011).
10.9×	Amendment to Promissory Note, dated September 28, 2011, between Richfield Oil & Gas Company and MacKov Investments Limited (incorporated by reference to Exhibit 10.10 to our registration statement on Form 10-12G filed on December 30, 2011).
10.10×	Letter Agreement, dated December 6, 2011, between Richfield Oil & Gas Company and Glenn MacNeil (incorporated by reference to Exhibit 10.11 to our registration statement on Form 10-12G filed on December 30, 2011).
10.11×	Settlement and Mutual Release Agreement, dated March 31, 2011, between Douglas C. Hewitt, Sr. and Hewitt Petroleum Inc (incorporated by reference to Exhibit 10.12 to our registration statement on Form 10-12G filed on December 30, 2011).
10.12×	Settlement and Mutual Release Agreement, dated March 31, 2011, between John McFadden and Hewitt Petroleum Inc (incorporated by reference to Exhibit 10.13 to our registration statement on Form 10-12G filed on December 30, 2011).
10.13×	Settlement and Mutual Release Agreement, dated March 31, 2011, between Paul S. Hewitt and Hewitt Petroleum, Inc. (incorporated by reference to Exhibit 10.14 to our Registration Statement on Form 10-12G filed on December 30, 2011) (incorporated by reference to Exhibit 10.14 to our registration statement on Form 10-12G filed on December 30, 2011).
10.14×	Letter Agreement, dated March 31, 2011 between Hewitt Petroleum, Inc. and J. David Gowdy (incorporated by reference to Exhibit 10.15 to our registration statement on Form 10-12G filed on December 30, 2011).
10.15×	Executive Agreement, dated March 31, 2011, between Hewitt Petroleum, Inc. and J. David Gowdy (incorporated by reference to Exhibit 10.16 to our registration statement on Form 10-12G filed on December 30, 2011).
10.16×	Executive Employment Agreement, dated March 31, 2011, between Hewitt Petroleum, Inc. and Douglas C. Hewitt, Sr. (incorporated by reference to Exhibit 10.17 to our registration statement on Form 10-12G filed on December 30, 2011).
10.17×	Termination of Executive Employment Agreement and Release, dated March 1, 2011, between Michael A. Cederstrom and Hewitt Petroleum, Inc. (incorporated by reference to Exhibit 10.18 to our registration statement on Form 10-12G filed on December 30, 2011).
10.18×	Termination of Executive Employment Agreement and Release, dated March 1, 2011, between R. Charles Muchmore and Hewitt Petroleum, Inc. (incorporated by reference to Exhibit 10.19 to our registration statement on Form 10-12G filed on December 30, 2011).
10.19×	Executive Employment Agreement, effective as of January 1, 2012, between Richfield Oil & Gas Company and Douglas C. Hewitt, Sr. (incorporated by reference to Exhibit 10.20 to our registration statement on Form 10-12G filed on December 30, 2011).
10.20×	Executive Employment Agreement, effective as of January 1, 2012, between Richfield Oil & Gas Company and Glenn G. MacNeil (incorporated by reference to Exhibit 10.21 to our registration statement on Form 10-12G filed on December 30, 2011).
10.21×	Financial Services Agreement, effective as of January 1, 2012, between Richfield Oil & Gas Company and MacKov Investments Limited (incorporated by reference to Exhibit 10.22 to our registration statement on Form 10-12G filed on December 30, 2011).

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10.22×	Executive Employment Agreement, effective as of January 1, 2012, between Richfield Oil & Gas Company and Michael A. Cederstrom (incorporated by reference to Exhibit 10.23 to our registration statement on Form 10-12G filed on December 30, 2011).
10.23×	Letter Agreement, dated December 12, 2011, between Richfield Oil & Gas Company and J. David Gowdy (incorporated by reference to Exhibit 10.24 to our registration statement on Form 10-12G filed on December 30, 2011).
10.24	Settlement Agreement, dated March 31, 2011, among Nostra Terra Oil & Gas Company, Hewitt Petroleum, Inc. and Hewitt Energy Group, Inc. (incorporated by reference to Exhibit 10.25 to our registration statement on Form 10-12G filed on December 30, 2011).
10.25	Settlement Agreement, dated March 31, 2011, among Tim J. Mahoney, Bloomfield LLC, M.I.C. Inc., Mahoney Investment Corporation, Inc., EC Services, LLC, Hewitt Energy Group, Inc., Hewitt Operating, Inc. and Hewitt Petroleum, Inc. (incorporated by reference to Exhibit 10.26 to our registration statement on Form 10-12G filed on December 30, 2011).

10.26	Addendum to Settlement Agreement, dated May 17, 2011, among Tim J. Mahoney, Bloomfield LLC, M.I.C. Inc., Hewitt Energy Group, Inc., Hewitt Operating, Inc. and Hewitt Petroleum, Inc. (incorporated by reference to Exhibit 10.27 to our registration statement on Form 10-12G filed on December 30, 2011).
10.27	Second Addendum to Settlement Agreement, dated July 7, 2011, among Tim J. Mahoney, Bloomfield LLC, M.I.C. Inc., Hewitt Energy Group, Inc., Hewitt Operating, Inc., Richfield Oil & Gas Company (formerly Hewitt Petroleum, Inc.) (incorporated by reference to Exhibit 10.28 to our registration statement on Form 10-12G filed on December 30, 2011).
10.28×	Extension of the Lease located in Sanpete County, Utah for 1,550 acres from Joseph P. Tate dated May 17, 2012, effective March 31, 2012 (incorporated by reference to Exhibit 10.29 to our registration statement on Form 10-12G/A filed on June 6, 2012).
10.29×	Lease located in Sanpete County, Utah for 404 acres from Joseph P. Tate dated May 31, 2012 (incorporated by reference to Exhibit 10.30 to our registration statement on Form 10-12G/A filed on June 6, 2012).
10.30×	Amendment to Promissory Note of MacKov Investments Limited in the amount of $287,713 dated May 24, 2012 (incorporated by reference to Exhibit 10.31 to our registration statement on Form 10-12G/A filed on June 6, 2012).
10.31+	Letter Agreement, dated June 28, 2012, between Richfield Oil & Gas Company and Skyline Oil, LLC (incorporated by reference to Exhibit 10.1 to our quarterly report on Form 10-Q for the quarter ended June 30, 2012).
10.32	Form of Letter Agreement between Richfield Oil & Gas Company and each of the Preferred Shareholders (incorporated by reference to Exhibit 10.1 to our current report on Form 8-K filed on December 26, 2012).
10.33×	Letter Agreement, dated November 28, 2012, between Richfield Oil & Gas Company and MacKov Investments Limited.
10.34×	Purchase and Sale Agreement of Liberty Working Interest, dated November 30, 2012, between Richfield Oil & Gas Company and MacKov Investments Limited.
10.35×	Purchase and Sale Agreement of HUOP Working Interest, dated December 11, 2012, between Richfield Oil & Gas Company and MacKov Investments Limited.
10.36×	Promissory Note, dated November 28, 2012, between Richfield Oil & Gas Company and MacKov Investments Limited.

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10.37×	Amendment to Promissory Note, dated January 2, 2013, between Richfield Oil & Gas Company and MacKov Investments Limited.
10.38×	Amendment to Executive Employment Agreement, dated February 15, 2013, between Richfield Oil & Gas Company and Douglas C. Hewitt, Sr.
10.39*	Amendment to Executive Employment Agreement dated January 15, 2014 between Richfield Oil & Gas Company and Douglas C Hewitt Sr.
10.40	Executive Employment Agreement dated May 6, 2013 between Richfield Oil & Gas Company and Alan Gaines.. (incorporated by reference to Exhibit 10.1 to our report on 8-K filed on May 7, 2013)
10.41*	Amendment to the Executive Employment Agreement dated May 6, 2013 between Richfield Oil & Gas Company and Alan Gaines.Subsidiaries of Richfield Oil & Gas Company.
10.42*	Lease Agreement dated March 28, 2014 between Richfield Oil & Gas Company and Joseph Tate and Jenifer Tate
23.1	Consent of Pinnacle Energy Services, L.L.C.
23.2*	Consent of Pinnacle Energy Services L.L.C. dated April 4, 2013
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Reserves and Engineering Evaluation of Pinnacle Energy Services, L.L.C., dated December 15, 2011 (incorporated by reference to Exhibit 99.1 to our registration statement on Form 10-12G filed on December 30, 2011).
99.2	Reserves and Engineering Evaluation of Pinnacle Energy Services, L.L.C., dated January 18, 2012 (incorporated by reference to Exhibit 99.2 to our registration statement on Form 10-12G/A filed on February 28, 2012).
99.3	Amendment to Reserves and Engineering Evaluation of Pinnacle Energy Services, L.L.C., dated January 18, 2012 (incorporated by reference to Exhibit 99.3 to our registration statement on Form 10-12G/A filed on June 6, 2012).
99.4	Second Amendment to Reserves and Engineering Evaluation of Pinnacle Energy Services, L.L.C., dated January 18, 2012 (incorporated by reference to Exhibit 99.4 to our registration statement on Form 10-12G/A filed on July 2, 2012).
99.5	Third Amendment to Reserves and Engineering Evaluation of Pinnacle Energy Services, L.L.C., dated August 13, 2012 (incorporated by reference to Exhibit 99.5 to our registration statement on Form 10-12G/A filed on August 17, 2012).
99.6	Reserves and Engineering Evaluation of Pinnacle Energy Services, L.L.C., dated January 18, 2013 (incorporated by reference to Exhibit 99.1 to our current report on Form 8-K filed on February 4, 2013).
99.7*	Reserves and Engineering Evaluation of Pinnacle Energy Services LLC dated April 4, 2014
101.INS*†	XBRL Instance Document
101.SCH*†	XBRL Taxonomy Extension Schema Document
101.CAL*†	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*†	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*†	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*†	XBRL Taxonomy Extension Presentation Linkbase Document
*	Filed herewith.

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**	Schedules and certain exhibits to this Exhibit 2.3 have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company will furnish copies of the omitted schedules and exhibits to the Securities and Exchange Commission upon its request.
×	Indicates management contract or compensatory plan or arrangement.
†	Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.
+	Confidential treatment has been requested for portions of this exhibit. These portions have been omitted and filed separately with the Securities and Exchange Commission.

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