SUN RIVER ENERGY, INC - FORM 10-K

Attached files

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EX-32.1 - SUN RIVER ENERGY, INC	snrv10kex321043012.htm
EX-31.1 - SUN RIVER ENERGY, INC	snrv10kex311043012.htm
EX-23.1 - SUN RIVER ENERGY, INC	snrv10kex231043012.htm
EX-31.2 - SUN RIVER ENERGY, INC	snrv10kex312043012.htm
EX-99.1 - SUN RIVER ENERGY, INC	snrv10kex991043012.htm
EX-32.2 - SUN RIVER ENERGY, INC	snrv10kex322043012.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10K

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

For the fiscal year ended April 30, 2012

¨ 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: 000-27485

SUN RIVER ENERGY, INC.

(Exact name of registrant as specified in its charter)

Colorado	84-1491159
State or other jurisdiction of	I.R.S. Employer
incorporation or organization	Identification No.

5646 Milton Street, Suite 130, Dallas, Texas 75206

(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (214) 369-7300

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

Title of each class		Name of each exchange on which registered
Common stock		OTC

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x 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 (ss. 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (ss. 229.405 of this chapter) 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. x

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 definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check One).

Large accelerated filer ¨	Accelerated filer	¨
Non-accelerated filer ¨	Smaller reporting company	x

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

The aggregate market value of the voting common stock held by non-affiliates of the registrant at October 31, 2011 was $29,456,192.

Number of shares of the registrant’s common stock outstanding at July27, 2012 was 41,193,670.

DOCUMENTS INCORPORATED BY REFERENCE:

Certain portions of the registrant's definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than August 28, 2012, in connection with the registrant's 2012 Annual Meeting of Stockholders, are incorporated herein by reference into Part III of this Annual Report on Form 10-K.

SUN RIVER ENERGY, INC.

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED APRIL 30, 2012

TABLE OF CONTENTS

		Page
PART I

ITEM 1 and ITEM 2	Business and Properties	9
ITEM 1A	Risk Factors	24
ITEM 1B	Unresolved Staff Comments	36
ITEM 3	Legal Proceedings	36
ITEM 4	Rescinded and Removed	37

PART II
		37
ITEM 5	Market for Registrant's Common Equity, Related Stockholder Matters
	and Issuer Purchases of Equity Securities
ITEM 6	Selected Financial Data	38
ITEM 7	Management's Discussion and Analysis of Financial Condition and
	Results of Operations	38
ITEM 7A	Quantitative and Qualitative Disclosures About Market Risk	43
ITEM 8	Financial Statements and Supplementary Data	F-1
ITEM 9	Changes in and Disagreements with Accountants on Accounting	43
	and Financial Disclosure
ITEM 9A	Controls and Procedures	43
ITEM 9B	Other Information	44

PART III (incorporated by reference to be filed with the Company’s Definitive Proxy Statement)

ITEM 10	Directors, Executive Officers, and Corporate Governance	44
ITEM 11	Executive Compensation	44
ITEM 12	Security Ownership of Certain Beneficial Owners and Management and	44
	Related Stockholder Matters
ITEM 13	Certain Relationships and Related Transactions, and Director Independence	44
ITEM 14	Principal Accounting Fees and Services	45

PART IV

ITEM 15	Exhibits, Financial Statement Schedules	45

SIGNATURES		45

Forward-Looking Statements

Certain statements contained in this Annual Report on Form 10-K are not statements of historical fact and constitute forward-looking statements within the meaning of the various provisions of the Securities Act of 1933, as amended, (the “Securities Act”) and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including, without limitation, the statements specifically identified as forward-looking statements within this report. Many of these statements contain risk factors as well. In addition, certain statements in our future filings with the SEC, in press releases, and in oral and written statements made by or with our approval which are not statements of historical fact constitute forward-looking statements within the meaning of the Securities Act and the Exchange Act. Examples of forward-looking statements, include, but are not limited to: (i) projections of capital expenditures, revenues, income or loss, earnings or loss per share, capital structure, and other financial items, (ii) statements about the plans and objectives of our management or board of directors including those relating to planned development of our oil and gas properties, (iii) statements of future economic performance and (iv) statements of assumptions underlying such statements. Words such as “believes,” “anticipates,” “expects,” “intends,” “targeted,” “may,” “will” “might,” “should,” “plan,” “predict,” “project,” “envision,” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

	•		changes in production volumes, worldwide demand and commodity prices for oil and natural gas;
	•		changes in estimates of proved reserves;

	•		declines in the values of our oil and natural gas properties resulting in impairments;
	•		the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves;

	•		our ability to acquire leases, drilling rigs, supplies and services on a timely basis and at reasonable prices;
	•		risks incident to the drilling and operation of oil and natural gas wells;
	•		future unanticipated production and development costs;

	•		the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on prices or costs;
	•		the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America and its individual states;

	•		changes in environmental laws and the regulation and enforcement related to those laws;
	•		the identification of and severity of environmental events and governmental responses to the events;

	•		legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, derivatives reform, and changes in state, federal and foreign income taxes;
	•		the effect of oil and natural gas derivatives activities; and

•

conditions in the capital markets.

Such forward-looking statements speak only as of the date on which such statements are made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made to reflect the occurrence of unanticipated events.

See also “Risk Factors.”

CERTAIN DEFINITIONS

Unless the context otherwise requires, the terms “we,” “us,” “our,” “ours,” “the Company” or “Sun River” when used in this report refer to Sun River Energy, Inc., together with our consolidated operating subsidiaries. When the context requires, we refer to these entities separately.

We have included below the definitions for certain terms used in this report:

3-D seismic – An advanced technology method of detecting accumulation of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

AFE – Authority for expenditure.

After payout – With respect to an oil or natural gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered.

AMI – Area of mutual interest.

Bbl – One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bbls/d or BOPD – Barrels per day.

Bcf – Billion cubic feet.

Bcfe – Billion cubic feet equivalent, determined using the ratio of six thousand cubic feet (Mcf) of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Before payout – With respect to an oil and natural gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered.

Behind-pipe reserves – Those reserves expected to be recovered from completion interval(s) not yet open but still behind casing in existing wells.

BOE – Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

Carried interest – A contractual arrangement, usually in a drilling project, whereby all or a portion of the working interest cost participation of the project originator is paid for by another party in exchange for earning an interest in such project.

Completion – The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Compression – A force that tends to shorten or squeeze, decreasing volume or increasing pressure.

DD&A – Depreciation, depletion and amortization.

Developed acreage – The number of acres which are allotted or assignable to producing wells or wells capable of production.

Development activities – Activities following exploration including the installation of facilities and the drilling and completion of wells for production purposes.

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

Dry hole or well – A well found to be incapable of producing hydrocarbons economically.

EUR – Expected ultimate recovery from a well, reservoir or field.

Exploitation – The act of making oil and gas property more profitable, productive or useful.

Exploratory well – A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Farm-in or Farmout – An agreement where the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty and/or reversionary interest in the lease. The interest received by the assignee is a “farm-in” while the interest transferred by the assignor is a “farmout.”

FASB – The Financial Accounting Standards Board.

Field – An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

GAAP – Generally accepted accounting principles in the United States of America.

Gross acres or gross wells – The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling – A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques that may, depending on horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

Injection well – A well to inject gas, water, or liquefied petroleum gas under high pressure into a producing formation to maintain sufficient pressure to produce the recoverable reserves.

Mineral Rights - Ownership of minerals under a defined surface along with the legal right of access so the minerals can be extracted. Mineral rights can be separated and transferred from land ownership. Also called subsurface rights.

MBbls – One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE –One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

Mbtu (Mmbtu) – Used as a standard unit of measurement for natural gas and provides a convenient basis for comparing the energy content of various grades of natural gas and other fuels. One cubic foot of natural gas produces approximately 1,000 BTUs, so 1,000 cubic feet of gas is comparable to 1 MBTU. MBTU is often expressed as MMBTU, which is intended to represent a thousand BTUs.

Mcf – One thousand cubic feet.

Mcf/d – One thousand cubic feet per day.

Mcfe – One thousand cubic feet equivalent determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher for crude oil than natural gas on an energy equivalent basis although there have been periods in which they have been lower or substantially lower.

MMcf – One million cubic feet.

MMcf/d – One million cubic feet per day.

MMcfe – One million cubic feet equivalent.

Net acres or net wells – The sum of the fractional working interests owned in gross acres or gross wells.

NGL’s – Natural gas liquids measured in barrels.

NRI or Net Revenue Interests – The share of production after satisfaction of all royalty, oil payments and other non-operating interests.

Normally pressured reservoirs – Reservoirs with a formation-fluid pressure equivalent to 0.465 PSI per foot of depth from the surface. For example, if the formation pressure is 4,650 PSI at a depth of 10,000 feet, the pressure is considered to be normal.

Over-pressured reservoirs – Reservoirs with a formation fluid pressure greater than 0.465 PSI per foot of depth from the surface.

Plant products – Liquids generated by a plant facility; including propane, iso-butane, normal butane, pentane and ethane.

Plugging and abandonment or P&A – Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

PV10% – The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with United States Securities and Exchange Commission guidelines, net of estimated lease operating expense, production taxes and future development costs, using prices, as prescribed in the United States Securities and Exchange Commission rules, and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion and amortization, or Federal income taxes and discounted using and annual discount rate of 10%. PV10% is considered a non-GAAP financial measure as defined by the United States Securities and Exchange Commission.

Primary recovery – The first stage of hydrocarbon production in which natural reservoir drives are used to recover hydrocarbons, although some form of artificial lift may be required to exploit declining reservoir drives.

Productive well – A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed nonproducing reserves or PDNP – Proved developed nonproducing reserves are proved reserves that are either shut-in or are behind-pipe reserves.

Proved developed producing reserves or PDP – Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.

Proved developed reserves – Proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) the area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a

highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) the project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved reserves – The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped location – A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUD – 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.

Recompletion – The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.

Re-engineering –A process involving a comprehensive review of the mechanical conditions associated with wells and equipment in producing fields. Our re-engineering practices typically result in a capital expenditure plan, which is implemented over time, to workover (see below) and re-complete wells and modify down-hole artificial lift equipment and surface equipment and facilities. The programs are designed specifically for individual fields to increase and maintain production, reduce down-time and mechanical failures, lower per-unit operating expenses, and therefore, improve field economics.

Reprocessing – Taking older seismic data and performing new mathematical techniques to refine subsurface images or to provide additional ways of interpreting the subsurface environment.

Reservoir – A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty – The portion of oil, gas, and minerals retained by the lessor on execution of a lease or their cash value paid by the lessee to the lessor or to one who has acquired possession of the royalty rights, based on a percentage of the gross production from the property free and clear of all costs except taxes.

Royalty interest – An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

SEC – The U.S. Securities and Exchange Commission.

Secondary recovery – The use of water-flooding or gas injection to maintain formation pressure during primary production and to reduce the rate of decline of the original reservoir drive.

Shut-in reserves – Those reserves expected to be recovered from completion intervals that were open at the time the reserve was estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or pipelines were not yet installed.

Standardized Measure of Discounted Future Net Cash Flows – Present value of proved reserves, as adjusted to give effect to estimated future abandonment costs, net of estimated salvage value of related equipment, and estimated future income taxes.

Timber Rights– Ownership of freestanding timber under a defined surface along with the legal right of access so the timber can be extracted.

Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest or WI – The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and share of production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development operations and all risks in connection therewith.

Workover – Operations on a producing well to restore or increase production.

PART I

ITEM 1 and ITEM 2 – BUSINESS and PROPERTIES

Overview of Our Business

Sun River Energy, Inc. (“Sun River” or the “Company”) is an exploration and production company focused on oil and natural gas. Sun River has mineral interests in two major geological areas. Each area has a distinct development plan, and each area brings a different value matrix to the Company. The Company has mineral interests in the Raton Basin located in Colfax County, New Mexico, and in several counties in the highly prolific East Texas Basin. The Company’s strategy is to predictably, consistently and profitably prove and develop these interests in order to maximize shareholder value.

Through our wholly-owned subsidiary, Sun River Operating, Inc., we manage all engineering and geologic research and evaluation, permitting, drilling, completion and production operations for our properties in Texas and New Mexico.

History and Acquisitions

Sun River was incorporated under the laws of the State of Colorado on April 30, 1998 as Dynadapt System, Inc. (“DSI”) to raise capital for an Internet website related project. On April 21, 2006, DSI acquired 100% of the issued and outstanding shares (8,633,333) of Sun River Energy, Inc. in exchange for 8,633,333 shares of the DSI’s common stock, as part of a Plan and Agreement of Reorganization, dated April 21, 2006. As part of the acquisition of Sun River, DSI acquired

222,855 acres of a mixture of fee oil and gas,timber, coal, mineral interest, a limited amount of coalbed methane fee interest, and approximately 34,000 acres oil and gas mineral leasehold. As a result of the Plan and Agreement of Reorganization, DSI changed its business operations to focus on the development of the Company as an independent energy company engaged in the exploration of North America, unconventional natural gas properties and conventional oil and gas exploration. On August 18, 2006, DSI changed its name to Sun River Energy, Inc.

Prior to the fall of 2009, the Company focused on the development of coalbed methane on property located in New Mexico. During the fall of 2009 and through the summer of 2010 we began shifting our focus from the development of coalbed methane to emphasize the identification of deep-basin-centered hydrocarbons on our New Mexico properties. In connection with this shift in focus, we substantially changed our management team. Our current management team has significant experience in the development of basin-centered gas plays, such as those believed to exist on our New Mexico properties, as well as the highly prolific areas of the East Texas Basin and West Texas. Our current areas of interest include acreage positions in East Texas which provide the Company with both reserves and production in a known basin, along with the opportunity for low risk, infill development drilling in mature fields.

On February 7, 2011, the Company completed the purchase of certain oil and gas leases and leasehold interests (the “Katy Acquisition”) with Katy Resources ETX, LLC, (“Katy”) a Delaware limited liabilitycompany. The assets acquired are (a) certain of Katy’s oil and gas leases and leasehold interests in Angelina, Cherokee, Houston and Panola Counties in East Texas; (b) four wellbores consisting of three producing wells each holding one of the three gas units being acquired and one shut-in well; (c) all contracts or agreements related to the foregoing lands, leases and wells; (d) all equipment located on the land or used in the operation of the foregoing land, leases or wells; and (e) all hydrocarbons produced from or attributable to the foregoing land, the leases and the wells and other related assets. The aggregate purchase price was $11.7 million, subject to purchase price adjustments. The Katy Acquisition includes total acreage held by production of 1,864 gross acres (1,150 net acres). This purchase also included 6,687 gross acres (6,284 net acres) under primary terms on numerous leases. Three of the producing wells and surrounding acreage have been unitized under Texas Railroad Commission rules. Under the terms of the agreement, the purchase price was be paid in the form of (i) $1 million in cash, (ii) $4 million in the form of a note payable, and secured by a deed of trust, and (iii) 1,583,710 shares of the Company’s restricted Common Stock.

As of May 31, 2011, the Company issued 500,000 shares of its 8% Series A Cumulative Convertible Preferred Stock for $10,000,000 with net proceeds to the Company of $9,401,600. The Company has authorized payment of the dividend associated with the preferred stock in restricted common shares, as provided for in the Certificate of Designation. The company has authorized the conversion of the preferred shares into common shares.

On April 25, 2011, the Board approved an amendment (the “Bylaw Amendment”) to the Company’s bylaws. The Bylaw Amendment allows the Company to issue uncertificated shares of the Company’s stock in addition to certificated shares. The Bylaw Amendment also states that, at shareholders’ meetings, one-third of all shares entitled to vote shall constitute a quorum, as that term is used in the Company’s Articles of Incorporation. The Board approved the Bylaw Amendment to conform to legal requirements, in relation to potential listing on a national stock exchange.

On May 31, 2011, the Company purchased EnCana Oil & Gas (USA) Inc.’s working interest and corresponding royalty interest in the Company’s three Houston County, Texas wells and corresponding leasehold acreage plus EnCana’s interest in the pipelines connected to these wells. The purchase price was $225,000. This acquisition gives Sun River 100% of the working interest in these wells and corresponding leasehold acreage in addition to 100% interest in the pipelines. The purchase was effective as of March 1, 2011.

As of July 27, 2012, Sun River Energy, Inc. (the "Company") entered into a Contract for Sale (“Agreement”) with Mericol, Inc. (“Buyer”) to sell only its gold, silver, iron ore, copper and coal interests in Colfax County, New Mexico. The Company will retain all other mineral interests or mineral extracts and timber interests. The Company is also granting Buyer a three (3) year option to acquire a 5% working interest in any oil and/or gas (including coalbed methane) wells drilled on the Company’s lands. The Agreement has an effective date of July 27, 2012 (the “Effective Date”).

Under the terms of the Agreement, Buyer paid the Company the Purchase Price consisting of the following: (1) five hundred thousand dollars ($500,000) and (2) two million five hundred sixty four thousand one hundred and three (2,564,103) shares of Buyer’s common stock (the “Shares”), which shall be subject to a lock-up period of twelve (12) months.

For a period of three (3) years from the effective date, the Company has the right to nominate one (1) director to the board of directors of Buyer, and to the extent permitted by applicable law, the Buyer shall use its reasonable efforts to cause the election of the Company’s nominee to the Buyer’s board of directors. If the Company’s designee to Buyer’s board of directors is not elected to the board at any annual or special general meeting of the shareholders of Buyer at which the designee stood for election, then no later than three (3) days following such meeting of the shareholders, the Buyer shall appoint a replacement director designated in writing by the Company to the Buyer’s board either by expanding the size of the board or, to the extent permitted by applicable law, causing a board member not designated by the Company to resign.

For a period of three (3) years following the effective date, Buyer agrees to file with the SEC all periodic reports (including Forms 10-K and 10-Q) required by the Securities and Exchange Act of 1934.

Buyer agrees, on or before the expiration of three (3) years of the effective date to spend at least one million dollars ($1,000,000) towards obtaining a National Instrument 43-101 report, or other comparable report, regarding the interests being sold to Buyer. If Buyer does not timely spend at least one million dollars ($1,000,000) towards obtaining a National Instrument 43-101 report, then Buyer, upon written demand from Seller and to the extent permitted by applicable law, agrees to cause Buyer’s then existing directors (other than any director appointed by Seller) to immediately resign, and Seller will have the right to appoint an additional number of directors to Buyer’s board such that Seller will have a majority representation on Buyer’s board of directors. If any of Buyer’s board members refuses or otherwise fails to resign within ten (10) calendar days of the date giving rise to the resignation event, then the Company shall have the right to call and hold a special meeting of stockholders for the purpose of removing such director.

On March 5, 2012, the Company announced it is shifting its development focus from its natural gas assets to its oil assets. As the price of natural gas declines the Company has determined a greater value in the development of our oil assets.

Management Employment Contracts

On June 4, 2012, Sun River Energy, Inc. (the “Company” or “Sun River”) entered into a Secured Convertible Promissory Note (the “Note”) with Sierra Foxtrot, LP (the “Payee”). Sierra Foxtrot, LP is the family partnership of the Company’s Chairman of the Board, President and Chief Executive Officer, Donal R. Schmidt, Jr. Mr. Schmidt Mr. Schmidt is a limited partner Sierra Foxtrot, LP and is the managing member of Sierra Foxtrot, LP’s general partner, Sierra Foxtrot GenPar, LLC.

Payee and Mr. Schmidt accepted the Note in settlement of the amounts owed to Mr. Schmidt by the Company for failure of the Company to perform under Mr. Schmidt’s Employment Agreement. The Note is for a six month term and is due December 4, 2012. The principal amount of the Note is for Two Million Five Hundred Forty Five Thousand Eight Hundred Ninety Six and 10/100 Dollars ($2,545,896.10) and it bears an interest rate of four percent (4%) per annum. The Company may prepay the Note at any time without penalty or premium, upon 10 days written notice Payee and subject to the Payee’s right to convert as provided for in the Note.

Prior to the Due Date, Payee shall have the option in its sole discretion, upon written notice to the Company, to convert all or part of the principal balance and interest, but not the employer or employee taxes, into shares of common stock of the Company at a price per share equal to $0.20 per share. After the Due date, Payee of the Note shall have the option, in its sole discretion, upon written notice to the Company, to convert all or part of the principal balance and interest, but not the employer or employee taxes, into shares of common stock of the Company at a price per share equal to 85% of the closing price per share on the date immediately preceding the date of the written notice.

A default exists under this note if (1) Maker fails to timely pay or perform any obligation or covenant in this Note or any written agreement between Payee and Maker or any Other Obligated Party; (2) any warranty, covenant, or representation in this note or in any other written agreement between Payee and Maker is materially false when made; (3) a receiver is appointed for Maker or any property on which a lien or security interest is created as security (the "Collateral Security") for any part of this note; (4) any Collateral Security is assigned for the benefit of creditors; (5) a bankruptcy or insolvency proceeding is commenced by Maker; (6) (a) a bankruptcy or insolvency proceeding is commenced against Maker and (b) the proceeding continues without dismissal for sixty days, the party against whom the proceeding is commenced admits the material allegations of the petition against it, or an order for relief is entered; (7) the Maker is dissolved, begins to wind up its affairs, is authorized to dissolve or wind up its affairs by its governing body or persons, or any event occurs or condition exists that permits the dissolution or winding up of the affairs of the Maker; (8) a Change in Control of Maker occurs as set forth in the definition below; or (8) any Collateral Security is impaired by loss, theft, damage, levy and execution, issuance of an official writ or order of seizure, or destruction, unless it is promptly replaced with collateral security of like kind and quality or restored immediately to its former condition.

Change in Control Defined. For purposes of this note, "Change in Control" shall mean the occurrence of any of the following:

(i) any person or "group" (within the meaning of Section 13(d)(3) of the 1934 Act), acquiring "beneficial ownership" (as defined in Rule 13d-3 under the 1934 Act), directly or indirectly, of fifty percent (50%) or more of the aggregate voting power of the capital stock ordinarily entitled to elect directors of the Company;

(ii) the sale of all or substantially all of the Company's assets in one or more related transactions to a person other than such a sale to a subsidiary of the Company which does not involve a change in the equity holdings of the Company; or

(iii) any merger, consolidation, reorganization or similar event of the Company or any of its subsidiaries, as a result of which the holders of the voting stock of the Company immediately prior to such merger, consolidation, reorganization or similar event do not directly or indirectly hold at least fifty-one percent (51%) of the aggregate voting power of the capital stock of the surviving entity.

On June 4, 2012, Sun River Energy, Inc. (the “Company” or “Sun River”) entered into a Secured Convertible Promissory Note (the “Note”) with its Chief Operating Officer, Thimothy S. Wafford (the “Payee”).

Payee accepted the Note in settlement of the amounts owed to Payee by the Company for failure of the Company to perform under his Employment Agreement. The Note is for a six month term and is due December 4, 2012. The principal amount of the Note is for Two Million Five Hundred Forty Five Thousand Eight Hundred Ninety Six and 10/100 Dollars ($2,545,896.10) and it bears an interest rate of four percent (4%) per annum. The Company may prepay the Note at any time without penalty or premium, upon 10 days written notice Payee and subject to the Payee’s right to convert as provided for in the Note.

Change in Control Defined. For purposes of this note, "Change in Control" shall mean the occurrence of any of the following:

On June 4, 2012, Sun River Energy, Inc. (the “Company” or “Sun River”) entered into a Secured Convertible Promissory Note (the “Note”) with its General Counsel and Secretary, James E. Pennington (the “Payee”).

Payee accepted the Note in settlement of the amounts owed to Payee by the Company for failure of the Company to perform under his Employment Agreement. The Note is for a six month term and is due December 4, 2012. The principal amount of the Note is for Two Hundred Ninety Eight Thousand Seven Hundred Ninety One and 57/100 Dollars ($298,791.57) and it bears an interest rate of four percent (4%) per annum. The Company may prepay the Note at any time without penalty or premium, upon 10 days written notice Payee and subject to the Payee’s right to convert as provided for in the Note.

Change in Control Defined. For purposes of this note, "Change in Control" shall mean the occurrence of any of the following:

The Notes with Sierra Foxtrot, LP, Thimothy S. Wafford and James E. Pennington (collectively the “Mortgagees”) are secured by a Mortgage, Security Agreement, Financing Statement and Assignment of Production and Revenue signed by Sun River Energy, Inc. on June 4, 2012 (the “Mortgage”). The Mortgage covers the entire right, title and interest of the Company of whatsoever kind and nature, including but not limited to interest in coal, oil and gas, gold, silver, timber and any other mineral rights of any type and nature, or any real property rights, oil and gas leasehold interests, royalty interests, and overriding royalty interest owned by the Company in any and all land located in Colfax County, New Mexico.

Under the Mortgage, the Company mortgaged, granted, bargained, sold, assigned and conveyed unto Mortgagees, with mortgage covenants, the following: an undivided 47.5% unto Mortgagee Sierra Foxtrot, LP, an undivided 47.5% unto Mortgagee Thimothy S. Wafford and an undivided 5% unto Mortgagee James E. Pennington, in and to:

A. The entire right, title and interest of Mortgagor of whatsoever kind and nature, including but not limited to interests in coal, oil and gas, gold, silver, timber and any other base or precious metals, and any other mineral rights of any type and nature, or any real property rights, oil and gas leasehold interests, royalty interests, and overriding royalty interests owned by Company in any and all land located in Colfax County, New Mexico.

B. All of Company’s interests (whether now owned or hereafter acquired by operation of law or otherwise) in and to all presently existing and hereafter created oil, gas and/or mineral unitization, pooling and/or commoditization agreements, declarations and/or orders, and in and to the properties covered and the units created thereby (including, without limitation, units formed under orders, rules, regulations or other official acts of any federal, state or other authority having jurisdiction and the so called "working interest units" created under operating agreements or otherwise), which cover, affect or otherwise relate to the properties owned by Company in Colfax County, New Mexico;

C. All of Company’s interests in and rights under (whether now owned or hereafter acquired by operation of law or otherwise) all presently existing and hereafter created operating agreements, equipment leases, production sales, purchase, exchange and/or processing agreements, transportation agreements, farmout and/or farm-in agreements, salt water disposal agreements, area of mutual interest agreements, and other contracts and/or agreements which cover, affect, or otherwise relate to the properties described above or to the operation of such properties or to the treating, handling, storing, transporting or marketing of oil, gas or other minerals produced from (or allocated to) such property;

D. All of Company’s interest (whether now owned or hereafter acquired by operation of law or otherwise) in and to all equipment, improvements, materials, supplies, fixtures and other property (including, without limitations all wells, pumping units, wellhead equipment, tanks, pipelines, flowlines, gathering lines, compressors, dehydration units, separators, meters, buildings, and power, telephone and telegraph lines) and all easements, servitudes, rights-of-way, surface leases and other surface rights, which are now or hereafter used, or held for use, in connection with the properties described above, or in connection with the treating, handling, storing, transporting, or marketing of oil, gas or other minerals produced from (or allocated to) such property;

E. All oil, gas, other hydrocarbons, and other minerals produced from or allocated to the Mortgaged Property, and any products processed or obtained therefrom (herein collectively called the "Production");

F. All equipment, inventory, improvements, fixtures, accessions, goods and other personal property of whatever nature now or hereafter located on or used or held for use in connection with the Mortgaged Property (or in connection with the operation thereof or the treating, handling, storing, transporting, processing, or marketing of Production) and all renewals or replacements thereof or substitutions therefor;

G. All contract rights, contractual rights, and other general intangibles related to the Mortgaged Property, the operation thereof (whether Mortgagor is operator or non-operator), or the treating, handling, storing, transporting, processing, or marketing of Production, or under which the proceeds of Production arise or are evidenced or governed;

H. All proceeds of the Collateral or payments in lieu of Production from the Collateral (such as take-or-pay payments), whether such proceeds or payments are goods, money, documents, instruments, chattel paper, securities, accounts, general intangibles, fixtures, real property, or other assets.

Messrs. Schmidt, Wafford and Pennington have each agreed to continue to perform their respected duties as officers and/or directors for the next six (6) months on an at-will basis for the following salaries:

a) Donal R. Schmidt, Jr. – $25,000 per month and if the Company is not able to pay cash he agrees to accept 125,000 shares of common stock of the Company per month in lieu thereof;

b) Thimothy S. Wafford – $25,000 per month and if the Company is not able to pay cashhe agrees to accept 125,000 shares of common stock of the Company per month in lieu thereof; and

c) James E. Pennington – $18,750 per month and if the Company is not able to pay in cash, then Mr. Pennington, may at his option, accept shares of common stock of the Company based upon a per share price of $0.20 for any portion of his salary in lieu of cash.

Effective June 4, 2012, Donal R. Schmidt, Jr. terminated his Employment Contract with Sun River Energy, Inc. (the “Company”) for good reason for the Company’s failure to pay his compensation and bonus for the year ending April 30, 2011 under the Employment Contract. The definition of Good Reason in Section 4 of the Employment Agreement, includes but is not limited to, the Company’s failure to timely pay any compensation or bonuses due to the Employee under the Employment Agreement. Mr. Schmidt provided the Company with notice of its failure to pay his Base Salary and bonus and waited past the 30 day cure period. Pursuant to Section 5(a) of the Employment Contract if the Employment Contract is terminated for Good Reason, the Company is liable for the following:

(i)	Any unpaid Base Compensation accrued through the date of termination;
(ii)	Any unreimbursed expenses properly incurred prior to the date of termination;

(iii)	Any awards previously granted pursuant to the Stock Plan that have fully vested and, if applicable, exercisable, on the date of such termination of employment;
(iv)	Any amounts or rights to which Mr. Schmidt is entitled under any other written agreements with the Company or written Company policy or pursuant to any Company benefit or welfare plans in effect on the date of termination;
(v)	In year two, one lump-sum payment of severance pay equal to two (2) times the Base Compensation.
(vi)	Beginning in year three and any subsequentyear in which this contract is in effect, one lump-sum payment of severance equal to two (2) times the annualized Base Compensation Rate (at the rate then in effect at the time of such termination) for the remainder of the Term.

Payments due under clauses (i) and (ii) above shall be paid by the Company within ten (10) days after the date of termination of Mr. Schmidt’s employment. Paymentsunder clauses (iii) and (iv) shall be paid pursuant to the terms of the applicable agreements or plans. Payments under clause (v) shall be paid within thirty (30) days after the date of termination.

The Company entered into the Secured Convertible Promissory Note with Sierra Foxtrot, LP, set forth above in Item 1.01, in full satisfaction of the termination of Mr. Schmidt’s Employment Agreement.

Effective June 4, 2012, Thimothy S. Wafford, Chief Operating Officer, terminated his Employment Contract with Sun River Energy, Inc. (the “Company”) for good reason for the Company’s failure to pay his compensation and bonus for the year ending April 30, 2011 under the Employment Contract. The definition of Good Reason in Section 4 of the Employment Agreement, includes but is not limited to, the Company’s failure to timely pay any compensation or bonuses due to the Employee under the Employment Agreement. Mr. Wafford provided the Company with notice of its failure to pay his Base Salary and bonus and waited past the 30 day cure period. Pursuant to Section 5(a) of the Employment Contract if the Employment Contract is terminated for Good Reason, the Company is liable for the following:

(i)	Any unpaid Base Compensation accrued through the date of termination;
(ii)	Any unreimbursed expenses properly incurred prior to the date of termination;

(iii)

Any awards previously granted pursuant to the Stock Plan that have fully vested and, if applicable, exercisable, on the date of such termination of employment;

(iv)	Any amounts or rights to which Mr. Wafford is entitled under any other written agreements with the Company or written Company policy or pursuant to any Company benefit or welfare plans in effect on the date of termination;

(v)	In year two, one lump-sum payment of severance pay equal to two (2) times the Base Compensation.
(vi)	Beginning in year three and any subsequent year in which this contract is in effect, one lump-sum payment of severance equal to two (2) times the annualized Base Compensation Rate (at the rate then in effect at the time of such termination) for the remainder of the Term.

Payments due under clauses (i) and (ii) above shall be paid by the Company within ten (10) days after the date of termination of Mr.Wafford’s employment. Paymentsunder clauses (iii) and (iv) shall be paid pursuant to the terms of the applicable agreements or plans. Payments under clause (v) shall be paid within thirty (30) days after the date of termination.

The Company entered into the Secured Convertible Promissory Note, set forth above in Item 1.01, in full satisfaction of the termination of Mr. Wafford’s Employment Agreement.

On June 4, 2012, James E. Pennington terminated his Employment Contract with Sun River Energy, Inc. (the “Company”) for good cause for the Company’s failure to pay his compensation under the Employment Contract. The definition of Good Cause in Section 8 of the Employment Agreement, includes but is not limited to, the Company’s failure to timely pay any compensation due to the Employee under the Employment Agreement and a reduction of the Employee’s compensation without Employee’s written consent. Mr. Pennington provided the Company with notice of its failure to pay his Base Salary and waited past the 30 day cure period. Pursuant to Section 9(b) of the Employment Contract if the Employment Contract is terminated for Good Cause the Company is liable for the following:

(vi)	on the sixth (6th) day following the Termination Date or the next regularly scheduled pay day of the Company following the Termination Date, respectively,
(A)		any accrued but unpaid Base Salary for services rendered through the Termination Date,

(B)	any accrued but unpaid expenses required to be reimbursed under Section 4 of the Employment Agreement, and
(C)	any vacation accrued to the Termination Date, and

(vii)

severance pay in an amount equal to Employee’s Base Salary for a period beginning on the Termination Date and ending one (1) year from the Termination Date or if the Termination Date occurs in the third (3rd) year of this Agreement then Employee shall receive his pro-rata Base Salary until the third (3rd) anniversary of the date of this Agreement. Payments shall be payable in equal monthly installments beginning on the last day of the first month following the Termination Date; provided, however, that none of the benefits payable under Section 9(b)(ii) will be payable unless, and the obligation to pay any severance pursuant to Section 9(b)(ii) shall not accrue until, the Employee has signed and delivered an executed general release, which has become irrevocable, satisfactory to the Company in its reasonable discretion, releasing the Company and its Affiliates and their respective officers, directors, managers, members, partners and employees from any and all claims or potential claims arising from or related to the Employee’s employment or termination of employment, and

(viii)

all 300,000 shares of common stock under the Stock Option.

The Company entered into the Secured Convertible Promissory Note set forth above in full satisfaction of the termination of Mr. Pennington’s Employment Agreement.

Effective July 1, 2012, Vice President of Engineering, Thomas Schaefer terminated his Employment Agreement with the Company for good cause for the Company’s failure to pay his compensation under the Employment Agreement. The definition of Good Cause in Section 8 of the Employment Agreement, includes but is not limited to, the Company’s failure to timely pay any compensation due to the Employee under the Employment Agreement and a reduction of the Employee’s compensation without Employee’s written consent. Mr. Schaefer provided the Company with notice of its failure to pay his Base Salary and waited past the 30 day cure period. Pursuant to Section 9(b) of the Employment Contract if the Employment Contract is terminated for Good Cause the Company is liable for the following:

(i)	on the sixth (6th) day following the Termination Date or the next regularly scheduled pay day of the Company following the Termination Date, respectively,
(A)	any accrued but unpaid Base Salary for services rendered through the Termination Date,

(B)	any accrued but unpaid expenses required to be reimbursed under Section 4 of the Employment Agreement, and
(C)	any vacation accrued to the Termination Date, and
(ii)	severance pay in an amount equal to Employee’s Base Salary for a period beginning on the Termination Date and ending one (1) year from the Termination Date or if the Termination Date occurs in the third (3rd) year of this Agreement then Employee shall receive his pro-rata Base Salary until the third (3rd) anniversary of the date of this Agreement. Payments shall be payable in equal monthly installments beginning on the last day of the first month following the Termination Date; provided, however, that none of the benefits payable under Section 9(b)(ii) will be payable unless, and the obligation to pay any severance pursuant to Section 9(b)(ii) shall not accrue until, the Employee has signed and delivered an executed general release, which has become irrevocable, satisfactory to the Company in its reasonable discretion, releasing the Company and its Affiliates and their respective officers, directors, managers, members, partners and employees from any and all claims or potential claims arising from or related to the Employee’s employment or termination of employment, and
(iii)	if the Employee terminates his employment for Good Reason, and thereafter engages in activities that are within the scope of the restrictions described in Section 7 of the Employment Agreement, Employee shall not be entitled to the severance payment described in clause (ii) of Section 9(b

During the year ended April 30, 2012, the Company defaulted on Jay Leaver, VP of Geology’s contract. Mr. Leaver continues to perform his duties, as the Company and Mr. Leaver work out a resolution to the Default.

During the year ended April 30, 2012, the Company defaulted on Judson F. Hoover, CFO’s contract. Mr. Hoover continues to perform his duties, as the Company and Mr. Hoover work out a resolution to the Default.

In light of the adverse market conditions affecting our common stock price, we recorded an impairment charge for the entire amount previously recorded for goodwill associated with the 2010 purchase of FTP assets. We utilized multiple market approaches to estimate the fair value of goodwill. In developing these fair value estimates, there was considerable judgment involved, particularly in determining the valuation methodologies to utilize and the weighting of different valuation methodologies applied. Certain key assumptions included the trading day period over which to assess market capitalization, implied control premium, multiple of earnings before interest, income taxes, depreciation and amortization and forecasted operating results. Our first step of the impairment test, which required us to compare the estimated fair value of the reporting unit to the carrying value, indicated that our goodwill was impaired. We then measured the impairment by allocating the fair value to the identifiable assets and liabilities of the reporting unit based on respective fair values and there was no residual value for goodwill; accordingly, we wrote off the entire carrying amount of goodwill.

Operations

East Texas Basin, Development Plan

Business Model – East Texas Basin

Sun River has acreage in the East Texas Basin and intends to increase its position through acquisitions and drilling. Sun River seeks to grow its reserves and production through predictable repeatable drilling generally limited to developmental and in-fill activities. As such, we target areas we believe are statistically predictable with respect to reserve valuation and costs. This leads the Company to generally focus on unconventional oil formations such as the Woodbine, Buda and Austin Chalk along with tight-gas sand type formations, such as the upper and lower Cotton Valley, the Travis Peak and the upper Bossier/Haynesville. Consequently, we usually avoid other types of unconventional gas with the exception of certain shale plays which meet our internal rate of return goals on a risk adjusted basis. Specifically, the Company does not currently intend to target coalbed methane, geopressured zones, or methane hydrates. The Company may evaluate some deep natural gas below 15,000 feet as our acreage is productive in certain areas. Following in this vein, we also will avoid horizontal drilling in many instances unless we believe the Economic Ultimate Recovery (“EUR”) is higher when drilled horizontally than vertically (although there are clear exceptions to this rule in certain types of plays).

With regard to oil or hydrocarbon liquids commonly known as condensate, we find that our areas yield gas that is “rich” with respect to liquids. As such, this gas ordinarily commands a higher price than that paid for “dry” gas. We do have some property that is productive for crude oil. On a case by case basis we will selectively target formations that are known crude producers.

Geological Discussion – East Texas Basin

The East Texas Basin extends from just east of Dallas-Ft. Worth eastward to the Texas/Louisiana state line. The city of Tyler sits close to its geographic center. It is bounded to the west by the Mexia Fault Zone, part of the Quachita Thrust Fold and Fault Complex, that marks an ancient buried mountain range of Pennsylvanian age (approximately 300 million years before present). To the east, it is bounded by the Sabine Arch, a broad uplift along the Texas/Louisiana state line. Its northern boundary is the Talco Fault Zone, just south of the Oklahoma-Texas border, and its southern border is the Elkhart-Mt Enterprise Fault Zone partway between Tyler and Houston. The basin began to assume its current outline in the late Cretaceous Period and preserves a thick sequence of Mesozoic sedimentary rock.

The East Texas Basin is the site of the nation's largest oil field outside of Alaska. It contains over 30,000 wells and has produced over 5.2 billion barrels since its discovery in 1930, primarily from the Cretaceous Woodbine formation, sourced from the Eagle Ford Shale.

The East Texas Basin contains rich source rocks, such as the Eagle Ford and Bossier/Haynesville, that are mature and source widespread basin-centered resource systems. Excellent reservoir units, such as the Cotton Valley Sand, Travis Peak, and Pettit Limestone, provide numerous structural and stratigraphic traps.

Sun River’s primary areas of interest in the East Texas Basin are in the Carthage Field in Panola County, Texas and various fields in Houston County, Texas, where Sun River’s acreage offsets both the Raintree Field and Decker Switch Field. The Carthage Field of East Texas is one of the major gas resource plays in North America with close to 10,000 wells drilled in Panola County alone, whose typical target horizons are the Cotton Valley sands and the Bossier/Haynesville shale. The Cotton Valley sand is predominantly gas, has a high probability of success, with strong repeatability, along with upside in overlying sands in the Pettit and Travis Peak. Typical wells in Sun River’s acreage will be drilled vertically to between 9,000 feet and 11,000 feet in order to penetrate the full column including the Bossier/Haynesville shale. With successful acreage capture, further development can include horizontal development of the thicker sand sections.

Sun River’s primary target in the Houston County area is the Travis Peak, with Cotton Valley, Rodessa, Glen Rose, Pettit, James Lime, Buda/Georgetown, and Woodbine containing additional pay zones. Sun River’s acreage was originally assembled as an extension of the SavellAmoruso Field where wells can produce as much as 50 BCF. Log analysis confirms the deep Bossier/Haynesville is present in Sun River acreage. The Raintree Field is the most analogous offset as it produces predominantly from the Travis Peak section. The Raintree Field, although discovered in the early 1980’s, did not begin development until 2005 and has already produced 35 BCFE from only 67 wells. With wells draining at most 40 acres, this area has significant upside potential. Typical development wells in the Raintree area are drilled vertically to between 12,000 feet and 14,400 feet. Using hydraulic fracturing, as much as 500 feet of net pay in the Travis Peak and Cotton Valley are stimulated and commingled with the Pettit and Glen Rose. James Lime, Buda/Georgetown, and Woodbine are typically produced with horizontal wells.

Current Holdings – East Texas Basin

The Company owns 4,925 gross acres (4,492 net acres) in the East Texas Basin. 2,554 gross acres (2,239 net acres) are held by production (“HBP”). As of May 1, 2012, McCartney Engineering, LLC Independent Petroleum Consulting Engineers estimates Total Proved Reserves in East Texas are 11 BBLs of Oil and 99,368 MCF of natural gas.

The Neal Heirs Gas Unit consists of one (1) producing well, the Neal Heirs # 1. The well is completed in the Carthage Field, Bossier/Haynesville formations. The Cotton Valley, Travis Peak and Pettit formations are behind pipe. Recently drilled vertical offsetting wells demonstrate EURs from 0.9 to 1.3 BCFE with some vertical wells in the area projected to recover as high as 2.1 BCFE. This gas unit is in the Lake Murvaul area which has been a core area for Devon and has allowed them to perfect horizontal Cotton Valley drilling techniques in over 92 wells. Within two miles of Sun River acreage, there are Horizontal Cotton Valley wells that can recover as much as 5 BCFE. There are currently 16 drill locations on 40 acre spacing.

The Southern portion of our East Texas acreage is in the Houston County area. It is comprised of several exploitation and exploration opportunities in and around existing gas units and various undrilled leasehold positions. The Temple Gas Unit, SGG Unit and TB Cutler Lease collectively have 38 more Travis Peak/Pettit/Glen Rose/James Lime locations. There are also approximately 55 deep drilling locations based upon 40 acre spacing.

All of the Houston County wells are all drilled in the Raintree Field. The Temple Gas Unit consists of one (1) shut in well, the Temple Gas Unit #1, completed in the Lower Travis Peak section and it demonstrates the Eastern extent of the known field. The SGG Unit consists of one (1) shut in well, the SGG Unit # 1, completed in the Travis Peak. The TB Cutler #1 well is completed in the Lower Travis Peak that has not yielded production in commercially viable quantities, and is awaiting recompletion in the Middle and Upper Travis Peak. . The Upper Travis Peak section is behind pipe as demonstrated by mud logs and open-hole logs. This well demonstrates the Western extent of the known field. The TB Cutler and Temple wells lie over 20 miles apart and demonstrate similar sand packages in the Travis Peak with net pay in excess of 500 feet that would suggest a Basin Centered Gas play.

Average wells in the Houston County area can range in EUR from 0.5 BCF to over 5 BCF with average wells in developed fields such as Raintree exhibiting 1.8 to 3.5 BCF. In the Lower Travis Peak section of the Temple, EUR is 1.5 BCF. Within close proximity to the Temple well and offsetting Sun River acreage, the Weatherford #1 is completed in the Upper Travis Peak section and demonstrates an EUR of 2.3 BCF. In the area, the Pettit and Glen Rose can add an additional 0.5 BCF per zone.

Colfax County Prospect, New Mexico Development Plan

Business Model – Colfax County Prospect

It is our express intent to develop the asset to its highest and best use. Since we own the property in New Mexico we have no specific timeline or constraints with how we manage and develop these assets. This is a unique and unquantifiable situation for which there is no readily available comparison. The nearly 275 square miles of various resources has a tremendous potential and must be carefully analyzed and managed. The Company’s stated purpose is to maximize these resources to increase shareholder value. We may do this through a number of mechanisms, limited only to the extent of our creative abilities. Subsequent to April 30, 2012, we entered into an agreement to sell our coal, gold, silver, copper and iron-ore interests (please see subsequent events, under Item I).Further, we may enter into one or more joint ventures or partnerships on all or part of the property. It is also conceivable we will sell all or part of the asset.

Geological Discussion – Colfax County Prospect

The Colfax County Prospect includes the southern Raton Basin, Cimarron Arch and northernmost Las Vegas Basin, as well as portions of the leading edge of the Sangre de Cristo Mountain thrust system. The Raton Basin and Las Vegas Basins are Laramide-aged features (approximately 70 to 55 million years old). The Raton Basin preserves Cretaceous- and Tertiary-aged rocks, whereas in the Las Vegas Basin, the Tertiary and upper Cretaceous has largely been eroded. The largest currently-producing hydrocarbon resource in the Raton Basin is Tertiary-aged coal bed methane. Sun River's northern acreage is prospective for coalbed methane exploration (“CBM”). Sun River drilled three CBM wells in 2007. These wells flared gas while drilling but were never completed due to rising completion costs. Additionally, several operators in the basin have reported success in drilling shale gas wells in the Pierre shale and Niobrara chalk. A substantial amount of Sun River's acreage is prospective in these horizons.

Additional potential is found in conventional reservoirs of Mesozoic (Dakota and Entrada) and Permian (Glorieta) age. There may be potential in fractured Precambrian on the leading edge of thrust faults, and in the late-Precambrian DeBaca Sequence, an oil-prone sedimentary sequence documented south of the area.

Sun River is currently focused on an exploration play concept in Pennsylvanian-aged rocks (approximately 300 million years ago). During the Pennsylvanian-aged Ancestral Rockies mountain-building event, ancient mountain ranges to the west and northeast of the project area shed sediments, including organic-rich shale and sandstones that are equivalent to the Atoka and Strawn in the Permian Basin, into a complex of deep fault-bounded basins. These basins have been termed ‘elevator basins’ because their typically steep fault bounded sides make them bear some resemblance to an elevator car. Elevator basins can be considered as ideal microcosms for the Basin Centered Gas model, wherein: a rich hydrocarbon source package is buried and matured, much of the resulting gas still in place in sandstone reservoirs interbedded with the source rock.

The prolific Granite Wash play in the Anadarko Basin is in many ways analogous to the elevator basin play. The Granite Wash formation is also of Pennsylvanian age, and filled the paleo Anadarko basin with coarse, immature sediments shed off the highlands along the southwest border of the basin. The main difference between this setting and an elevator basin is simply scale: the Anadarko Basin occupies several counties, whereas an elevator basin is at most twenty to thirty miles long and five to ten miles wide. An intriguing element to the Granite Wash story is the associated liquid production, which adds considerably to the revenue stream under current prices. Sun River’s elevator basin, the “Maxwell Sub-basin,” is on trend with the Anadarko Basin along the Amarillo-Wichita Lineament (Southern Oklahoma Aulacogen) and may also benefit from associated oil or condensate production.

Elevator basins have proven to be productive in the Broken Bone Graben on the Matador Arch in Texas, as well as in the Cuervo Sub-basin of the Tucumcari Basin of central eastern New Mexico which is directly south of the Raton Basin. Shell drilled four wells and completed five wells in 2009 and 2010 in the Cuervo Sub-basin. They brought a Liquefied Natural Gas plant on line in September 2010, and acquired approximately 30 square miles of 3D seismic. Shell was said to have leased deep rights to hundreds of thousands of acres in the Las Vegas and Raton Basins, presumably to further exploit this play concept, and staked a location for a 14,493 foot wildcat well in the northern portion of the Raton Basin just across the state line in Colorado. However, continued low prices for natural gas appear to have slowed the pace of the deep elevator-basin gas play considerably in the last year.

In the Colfax County Prospect, Sun River has identified a complex of elevator basins based on gravity and magnetic modeling with calibration using limited 2D seismic. The main basin of the complex is called internally the “Maxwell Sub-basin.” Identification of this complex was confirmed in a confidential report by Thomasson Partner Associates, Inc. of Denver, Colorado. This report was commissioned by Sun River in the summer of 2010 and completed in 2011. The report specifically identified seven (7) distinct elevator basin prospects on or immediately adjacent to Sun River’s Colfax County Prospect holdings.

The data indicates the Maxwell Sub-basin is up to 14,000 feet deep. It is expected that the top of the pay section should occur at or above 8,000 feet, resulting in pay sections of 6,000 feet in thickness or more in the deepest part of the sub-basin. Based on log and sample analysis of the nearest wells to penetrate significant thicknesses of this section, which were drilled by True and Amoco in the Las Vegas Basin in the early 1980s, we expect this section to be composed of interbedded sandstones and organic-rich shale, with up to 9% Total Organic Carbon (TOC) reported in several samples from the Las Vegas Basin wells. Log analysis and geologic setting both indicate the sandstones will provide better reservoirs than are found either in the Tucumcari or Matador Arch areas, primarily due to smaller amounts of carbonate rocks in the overall depositional package as compared to the analog areas.

The Maxwell Sub-basin complex lies in the southern margin of the Raton Basin proper and has been substantially under-explored to date. Historically, test wells in the area targeted positive structures, and while they often encountered strong shows of natural gas, this had relatively little economic value until recent decades. The buried elevator basins themselves have little to no surface expression: detecting and delineating them requires geophysical surveys. Only a small amount of seismic data has ever been acquired in the area, mostly by Shell in the late 1960s. Most of the deep penetrations in the area are situated along the uplifted flanks of the Maxwell Sub-basin, where the lower Pennsylvanian target section is missing due to non-deposition or erosion. Only two older wells in the area were drilled sufficiently off of structural highs to penetrate the lower Pennsylvanian section. The log character of these wells indicates the lower Pennsylvanian in the area contains abundant source rock, as indicated both by high gamma ray values and limited sampling reported by the New Mexico Bureau of Geology and Mineral Resources in 2012. An intriguing aspect of this area is the presence of the thick sections of the target horizon exposed in outcrop in the Sangre de Cristo Mountains to the west, where it was uplifted and exhumed during the Laramide tectonic event. In some outcrop areas, total lower Pennsylvanian section exceeds 8,000 feet in thickness. The presence of these exposures both allows detailed study of the deposition into elevator sub-basins.

Shell’s logs in the Cuervo Sub-basin reveal many hundreds of feet of sandstone with indications of gas, both from the mud logs and from density-neutron cross-over. However, little total porosity is indicated, probably due to deep burial and the presence of abundant carbonate rock in the section. It is common for rock packages that contain mixtures of carbonate and immature sandstones to develop significant cementation during diagenesis. At least two of the wells show signs of probable over-pressuring in the lower Pennsylvanian, as evidenced by increased drilling mud weights and deviation in shale porosity from the normal compaction profile. It appears that one of the wells tested significant water from perforations in the upper Precambrian, but in the lower Pennsylvanian significant water production does not seem to be a problem. At this stage of analysis, it appears that almost all available pore space is filled with natural gas, apparently slightly over pressured, which is consistent with the basin-centered-gas model. Production is limited by the amount of reservoir-quality rock in a given well-bore.

Several factors suggest that Sun River’s Maxwell Sub-basin occupies a more favorable setting than the Cuervo Sub-basin Shell has been testing in the Tucumcari Basin. First and foremost is the presence of a pipeline up the Interstate 25 corridor, which should readily allow production testing the first several wells. The Cuervo Sub-basin in the Tucumcari, in contrast, is over one hundred miles from the nearest pipeline. This forced Shell to build an expensive cryogenic plant in order to perform significant production testing. Additionally, the paleo-geographic setting of the Maxwell Sub-basin suggests it may contain less overall carbonate than the Cuervo Sub-basin, and therefore reservoir quality may be less degraded by diagenetic carbonate cements. The nearby wells in the Las Vegas Basin support this idea, having two to three percent more porosity than the corresponding section in the Cuervo Sub-basin. More porosity allows for more overall gas storage and higher reserves, and also allows for significantly better transport to the wellbore. It may be that the Maxwell Sub-basin may produce gas at commercial rates with significantly less hydraulic fracture stimulation than Shell has been applying in the Cuervo Sub-basin, but there is no way to be sure until several wells have been drilled and completed.

In addition to the deeper gas play, a shallow oil play exists on the flanks of the Maxwell Sub-basin. Sample cuttings of source rocks from wells in the nearby Las Vegas Basin indicate a portion of the Pennsylvanian-aged source material is likely to be oil-prone. The presence of oil-prone source rocks in the Maxwell Sub-basin would explain the occurrence of condensate in a key well on the northwest flank of the Sub-basin. Sun River is currently pursuing the possibility that some of the structures in the Sub-basin (those shallow enough to be above the dry gas window) may be charged with oil or condensate. These structures are well-delineated by the detailed gravity and magnetic data acquired by Sun River, and supported by limited surface geochemical data. Production may be from Granite Wash, as in the Palo Duro Basin / Whittenburg Trough area in Oldham County Texas, currently being explored by Apache. Apache’s area is on the east flank of the Sierra Grande Uplift, with the Granite Wash being sourced from the Sierra Grande Uplift. The Maxwell Sub-basin is on the west flank of the Sierra Grande uplift, and is likely to contain similar Granite Wash reservoirs. Besides the Granite Wash, other sandstones and carbonates could be excellent reservoirs in the Pennsylvanian system. The Campo Field, northeast of the Maxwell Sub-basin in Baca County, Colorado, has produced over five million barrels of oil from approximately 4,000 feet in depth from reservoirs in the Lansing-Kansas City (Pennsylvanian) interval. The structures identified in the Maxwell Sub-basin are less than 5,500 feet in depth, and so will likely have production characteristics more similar to Campo than to the Oldham County Granite Wash fields.

Sun River has also generated oil prospects targeting a structural crest up dip of show wells in the Cretaceous-aged Dakota Sandstone. This structural crest is known internally as the “Colfax Arch”, and separates the Maxwell Sub-basin from the main body of the Raton Basin. Depth to the Dakota in the area is between 2,000 and 2,500 feet.

Current Holdings – Colfax County Prospect

Sun River holds various ownership rights in fee simple to approximately 201,844 gross acres (190,638 net acres) in Colfax County, New Mexico. These rights include approximately 171,000 acres of oil and gas mineral rights, 154,000 acres of subsurface rights to hard rock minerals, excluding gold, silver copper, and iron-ore, and 39,374 acres of timber rights.Subsequent to April 30, 2012, we entered into an agreement to sell our hard rock minerals for certain interest (please see subsequent events, under Item I).

Sun River's mineral holdings were acquired through a quitclaim deed from The Maxwell Land Grant Company. The acreage is traced to a land grant formed under Spanish law and guaranteed by U.S. law under the terms of the Treaty of Guadalupe-Hidalgo that ended the Mexican-American war. The interests of the various original heirs to the land grant were consolidated by Lucien Maxwell who then sold the 1.7 million acre land grant to The Maxwell Land Grant Company in 1870.

The Maxwell Land Grant Company established full right to the property through prolonged legal battles, including multiple appearances before the US Supreme Court. Although it sold surface rights to settlers, it consolidated the coal rights and ran coal mining operations until 1950 when it sold its interests to a larger company. It used its timber rights to build structures and support for the coal mines and also conducted substantial gold and silver operations in the Elizabethtown-Baldy Mining District on the western edge of the county. The Maxwell Land Grant Company operated gold mines in this area until 1940.

Presently, there are no producing wells and three shut-in coalbed methane wells located on these properties.

Development Plans – Colfax County Prospect

The Company has substantially completed it geological interpretation phase relating to discovery wells. We are currently evaluating potential joint ventures, and other methods to develop our hydrocarbon holdings.

Sun River intends to purchase additional existing seismic data to more thoroughly and accurately delineate the prospective basins prior to any drilling activities beyond the test well phase.

Production

Production began during the last 60 days of 2011 fiscal year. During the year ended April 30, 2012 we produced and sold 60,972MCF of gas generating $293,000in revenues, generated from our five producing wells. The average price per MCF was $4.71. The Henry Hub natural gas cash ask priceon April 30, 2012 was $2.143. Our cash flow limitations may cause us to have the inability to pay saltwater disposal which may cause the wells to be shut-in.

Oil and Natural Gas Reserves

Revised Oil and Gas Reporting requirements

In December 2008, the Securities Exchange Commission of the United States announced that it had approved revisions to modernize the oil and gas reserves reporting requirements. Some of the significant changes under the modernized rules include:

·	Replaced year end prices with 12-month average price to calculate reserve estimates
·	Inclusion of oil and gas extracted from nontraditional sources in reserve estimates
·	Permitted use of new technologies that meet the definition of "reliable" to determine oil and gas reserves
·	Required disclosure of reserves by specific geographic area
·	Permitted disclosure of both probable and possible reserves
·	Requirement to include reports and related consents from third parties

We adopted the rules effective May1, 2010.

Controls Over Reserve Report Preparation

Estimates of proved reserves at May 1, 2012 were prepared by McCartney Engineering, LLC., independent petroleum consultants, a Colorado registered engineering firm. The technical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. These reserves are then reviewed and approved by our in-house petroleum engineers and geoscientists.

Reserve reports were prepared as of April 30, 2012.

Years Ended April 30, 2012

Estimated Proved Natural Gas and Oil Reserves:
Net natural gas reserves (Mcf):
	Proved developed		99,368
Net oil reserves (Bbls):
	Proved developed		11
Estimated Present Value of Net Proved Reserves:
PV-10 value (in thousands)
	Proved developed	$	155
Less: future income taxes, discounted at 10%			—
Standardized measure of discounted future net cash flows (in thousands)		$	155

Prices Used in Calculating Reserves:
Natural gas (per Mcf)		$	4.96
Oil (per Bbl)		$	95.48

As of April 30, 2012, the Company has seven gross, six net, wells. Six gross wells were purchased and one gross well was completed during the fourth quarter of 2011.

In light of the adverse market conditions affecting our ability to raise capital necessary to develop our reserves, we recorded an impairment charge for the entire amount previously recorded for property subject to amortization associated with the 2011 purchase of Katy assets. We utilized multiple market approaches to estimate the fair value of goodwill. In developing these fair value estimates, there was considerable judgment involved, particularly in determining the valuation methodologies to utilize and the weighting of different valuation methodologies applied. Certain key assumptions included the trading day period over which to assess market capitalization, implied control premium, multiple of earnings before interest, income taxes, depreciation and amortization and forecasted operating results. Our first step of the impairment test, which required us to compare the estimated fair value of the reporting unit to the carrying value, indicated that our goodwill was impaired. We then measured the impairment by allocating the fair value to the identifiable assets and liabilities of the reporting unit based on respective fair values and there was no residual value for goodwill; accordingly, we wrote off the entire carrying amount of goodwill.

Marketing

Our ability to market oil and natural gas often depends on factors beyond our control. The potential effects of governmental regulation and market factors, including alternative domestic and imported energy sources, available pipeline capacity, and general market conditions, are not entirely predictable.

Natural gas is generally sold pursuant to individually negotiated gas purchase contracts, which vary in length from spot market sales of a single day to term agreements that may extend several years. Customers who purchase natural gas include marketing affiliates of the major oil and gas companies, pipeline companies, natural gas marketing companies, and a variety of commercial and public authorities, industrial, and institutional end-users who ultimately consume the gas. Gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market may vary daily, reflecting changing market conditions. The deliverability and price of natural gas are subject to both governmental regulation and supply and demand forces.

The Company sells natural gas to one of three customers, Orion Pipeline, DCP Midstream, LLC, and Kinder Morgan Tejas Pipeline under gas-gathering agreements. All three customers are well capitalized and regulated. The Company does not anticipate any customer becoming unable to perform under their agreement.

Oil produced is sold at the prevailing field price to one or more of a number of unaffiliated purchasers in the area. Generally, purchase contracts for the sale of oil are cancelable on 30 days’ notice. The price paid by these purchasers is an established market or “posted” price that is offered to all producers.

Competition

We compete with major integrated oil and natural gas companies and independent oil and natural gas companies in all areas of our operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Many of our competitors have substantially greater financial and other resources than we have. Larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. Our competitors also may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have operated for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

At various times we may experience occasional or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and natural gas drilling. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and natural gas leases to lapse.

Regulation

Exploration and Production.The exploration, production and sale of oil and natural gas are subject to various types of local, state and federal laws and regulations. These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, allowable rates of production, restoration of surface areas, plugging and abandonment of wells and requirements for the operation of wells. Our operations are also subject to various conservation requirements.

Environmental Matters.The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of oil and natural gas wells.

The New Mexico Surface Owners Protection Act is a state statute governing the right to use the surface estate for purposes of exploiting the minerals in New Mexico. In general New Mexico has adopted the “accommodation doctrine” but has further modified the relative rights of the mineral owners and surface owners. This statute requires certain notification and compensation rights and responsibilities between mineral and surface owners. These rights can have significant time and resource requirements to the mineral owners.

There are numerous state laws and regulations in the states in which we operate that relate to the environmental aspects of our business. These state laws and regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and natural gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and natural gas wells that have been unproductive. Numerous state laws and regulations also relate to air and water quality. We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and natural gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, there can be no assurance that environmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our financial condition and results of operations. Even though liability insurance is available to cover unanticipated consequences of operations, environmental risks generally are not fully insurable. In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

Marketing and Transportation.Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the Federal Energy Regulatory Commission (“FERC”) that affect the economics of natural gas production, transportation and sales. In addition, FERC is

continually proposing and implementing new rules affecting segments of the natural gas industry, most notably interstate natural gas transmission companies, which remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.

Our sales of crude oil and condensate are currently not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. However, we do not believe that these regulations affect us any differently than other crude oil producers.

Financial Information about Geographic Areas

Our business is generated from within the United States of America and we have no long-lived assets located outside the United States of America.

Title to Properties

In most situations, as is customary in the oil and gas industry, only a preliminary title examination is conducted at the time we acquire oil and gas leases covering properties for possible drilling operations. Prior to the commencement of drilling operations, a more complete title examination of the drill site tract is usually conducted by independent attorneys or landmen. Once production from a given well is established, we prepare a division order title report indicating the proper parties and percentages for payment of production proceeds, including royalties. The level of title examination often differs from property to property. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect the carrying value of our properties.

Employees

At April 30, 2012, we had 8 full-time employees and one part-time employee. We believe that our relationships with our employees are good. None of our employees are covered by a collective bargaining agreement. From time to time, we use the services of independent consultants to perform various professional services, particularly in the areas of corporate compliance, legal, geological, permitting and environmental assessment activities. Independent contractors often perform well drilling and production operations, including pumping, maintenance, dispatching, inspection and testing.We are not current with our payroll obligations and are working to correct that position.

Offices

Our principal executive offices are located at 5646 Milton Street, Suite 130, Dallas, Texas 75206, and our telephone number is (214) 369-7300. We currently have a verbal agreement to lease space for our office in Dallas with our CEO and COO to reimburse them at cost.

Available Information

We file annual, quarterly and current reports, proxy statements and other information electronically with the United States Securities and Exchange Commission (“SEC”). You may read and copy any materials we file with the United States Securities and Exchange Commission at the United States Securities and Exchange Commission’s Public Reference Room at 100 F. Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the United States Securities and Exchange Commission at 1-800-SEC-0330. The United States Securities and Exchange Commission maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the United States Securities and Exchange Commission, including our filings.

Our internet address is www.snrv.com. We make available free of charge on or through our internet site our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the United States Securities and Exchange Commission.

ITEM 1A - RISK FACTORS

Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K.

If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected. In addition, the current global economic environment intensifies many of these risks.

We have incurred losses and may do so in the future.

At April 30, 2012 and 2011, we had an accumulated deficit of $41.0 million and $17.0 million and total stockholders' deficits of $1.1 million and $13.3 million, respectively. We have recognized a significant amount of annual net losses in the past. The uncertainty and factors described throughout this section may impede our ability to economically find, develop, exploit and acquire natural gas and oil reserves. We may not achieve or sustain profitability or positive cash flows from operating activities in the future.

Risks Relating to the Oil and Natural Gas Industry and Our Business

Oil and natural gas prices are volatile. Volatility in oil and natural gas prices can adversely affect our results and the price of our common stock. This volatility also makes valuation of natural gas and oil producing properties difficult and can disrupt markets.

Oil and natural gas prices have historically been, and are likely to continue to be, volatile. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. Some of the factors that cause these fluctuations are:

•	demand for oil and gas, which is affected by worldwide population growth, economic development and general economic and business conditions;
•	the domestic and foreign supply of oil and natural gas;

•	political and economic uncertainty and socio-political unrest;
•	the price of foreign imports;
•	political and economic conditions in oil producing countries, especially the Middle East and South America;
•	the ability of the Organization of Petroleum Exporting Countries ("OPEC") to set and maintain oil price and production controls;
•	the level of worldwide oil exploration and production activity;
•	the cost of exploring for, producing and delivering oil and gas;
•	weather conditions;
•	technological advances affecting energy consumption;
•	domestic and foreign governmental regulations;
•	proximity and capacity of oil and gas pipelines and other transportation facilities;
•	the price and availability of alternative energy;
•	variations between product prices at sales points and applicable index prices; and
•	shortages in equipment and personnel.

The long-term effects of these and other conditions on the prices of crude oil and natural gas are uncertain. Price volatility makes it difficult to budget and project the return on exploration and development projects involving our natural gas and oil properties and to estimate with precision the value of producing properties that we may own or propose to acquire.

Prices often disrupt the market for natural gas and oil properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties. Our annual and quarterly results of operations may fluctuate significantly as a result of, among other things, variations in natural gas and oil prices and production performance. In recent years, natural gas and oil price volatility has become increasingly severe.

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

The oil and natural gas industry is capital intensive. We spend and will continue to need a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and gas reserves. We have historically addressed our short and long-term liquidity needs through the use of cash flow provided by operating activities, borrowings, and the issuance of equity and debt securities. Without adequate financing we may not be able to successfully execute our operating strategy. The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include:

•	general economic and financial market conditions;
•	oil and natural gas prices;
•	our market value and operating performance;
•	timely issuance of permits and licenses by governmental agencies;
•	the success of our projects;
•	our success in locating and producing new reserves;
•	amounts of necessary working capital and expenses; and
•	the level of production from existing and new wells.

We may be unable to execute our operating strategy if we cannot obtain adequate capital. If low oil and natural gas prices, lack of adequate gathering or transportation facilities, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, it may limit or reduce our ability to obtain the capital necessary to sustain our operations.

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

A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of natural gas or oil. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. However, 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 prior to drilling and testing whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in sufficient quantities to recover drilling or completion costs or to be economically viable. If we drill wells in our current and future prospects that are identified as non-economic or dry holes, our drilling success rate may decline and materially harm our business. In sum, the cost of drilling, completing and operating any wells is often uncertain and new wells may not be productive.

Drilling for and producing natural gas and oil are high risk activities with many uncertainties that could have a material adverse effect on our business, financial condition or results of operations.

Our future success depends largely on the success of our exploration, exploitation, development and production activities. These activities are subject to numerous risks beyond our control, including the risk that we will not find any commercially productive natural gas or oil reservoirs. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties depends in part on the evaluation of geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our costs of drilling, completing, producing and operating wells are often uncertain before drilling commences. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

•	delays in obtaining drilling permits from applicable regulatory authorities;
•	unusual or unexpected geological formations;
•	unexpected drilling conditions, including ground shifting or quakes;
•	pressure or irregularities in geological formations;
•	equipment failures or accidents;

•	well blow-outs;
•	fires and explosions;
•	pipeline and processing interruptions or unavailability;
•	title problems;
•	objections from surface owners and nearby surface owners in the areas where we operate;
•	adverse weather conditions;
•	lack of market demand for natural gas and oil;
•	delays imposed by or resulting from compliance with environmental and other regulatory requirements;
•	shortages of or delays in the availability or delivery of drilling rigs and the delivery of equipment;
•	shortages of or greater demands of skilled labor; and
•	reductions in natural gas and oil prices.

Our future drilling activities may not be successful. Our drilling success rate could decline generally or within a particular area and we could incur losses by drilling unproductive wells. Also, we may not be able to obtain sufficient contracts covering our lease rights in potential drilling locations. We cannot be sure that we will ever drill our identified potential drilling locations, or that we will produce natural gas or oil from them or from any other potential drilling locations. Shut-in wells, curtailed production and other production interruptions may negatively impact our business and result in decreased revenues.

Operational impediments may hinder our access to natural gas and oil markets or delay our production.

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities.

We deliver natural gas and oil through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future. Our ability to produce and market natural gas and oil is affected and may be harmed by:

•	the lack of pipeline transmission facilities or carrying capacity;
•	federal and state regulation of natural gas and oil production; and
•	federal and state transportation, taxation and energy policies.

We may incur debt in order to fund our exploration and development activities, which would reduce our financial flexibility and could have a material adverse effect on our business, financial condition or results of operations.

We may incur debt in order to fund our operations, make future acquisitions or develop our properties. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, oil and gas prices, and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt or pay our debt at maturity. If we are unable to repay our debt at maturity with existing cash on hand, we could attempt to refinance the debt or repay the debt with the proceeds of a debt or equity offering. We may be unable to sell public debt or equity securities, or do so on acceptable terms to pay or refinance the debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, our market value and profitability of our operations at the time of the offering or other financing. If we do not have sufficient funds, are otherwise unable to negotiate renewals of our borrowings, or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

A decline in oil and natural gas prices would adversely affect our ability to meet our capital expenditure obligations, financial commitments, financial results, cash flows, access to capital and ability to grow.

Our revenues, operating results, cash flow, profitability and future rate of growth depend upon the prevailing prices of, and demand for, natural gas and oil. All of our operating revenues are derived from the sale of our oil and gas production. A continuing substantial or extended decline in oil and natural gas prices would have a material adverse effect on our financial position, our ability to meet capital expenditure obligations and commitments, our results of operations, our access to capital and the quantities of natural gas and oil that may be economically produced by us. A significant decrease in price levels for an extended period negatively affects us in several ways including:

•	our cash flow will be reduced, decreasing funds available for capital investments employed to replace reserves, increase production or to operate;
•	certain reserves will no longer be economic to produce, leading to both lower proved reserves and cash flow and may result in charges to earnings for impairment of the value of these assets; and
•	Access to other sources of capital, such as bank loans, equity or debt markets, could be severely limited or unavailable.

Based on crude and natural gas pricing in recent years, the Company's oil and gas revenues may from time to time decrease, resulting in a negative impact on liquidity. The Company's current plans to address lower crude and natural gas prices are primarily to reduce capital expenditures to a level equal to cash flow from operations, reduce operating expenses and seek additional capital financing. However, the Company's plans may not be successful in improving its results of operations and liquidity. If oil or natural gas prices decline significantly for extended periods of time in the future, we might not be able to generate enough cash flow from operations to meet our obligations and make planned capital expenditures, which could impair our liquidity and our ability to develop our properties and to operate.

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

No one can measure underground accumulations of oil and natural gas in an exact way. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated or understated. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and

natural gas prices, production levels, operating and development costs, drilling expenses, severance and excise taxes, capital expenditures, ownership and title matters, taxes and the availability of funds. The engineering process of estimating natural gas and oil reserves is complex and is not an exact science. It requires interpretations of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Estimates of reserves based on risk of recovery and estimates of expected timing and future net cash flows prepared or audited by different engineers, or by the same engineers at different times, may vary substantially. Because of the subjective nature of crude oil and natural gas reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:

•	the amount and timing of crude oil and natural gas production.
•	the revenues and costs associated with that production.
•	the amount and timing of future development expenditures.

Over time, our independent petroleum engineering consultants may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. Further, the potential for future reserve revisions, either upward or downward, is significantly greater than normal because a significant portion of our potential reserves are undeveloped.

In accordance with United States Securities and Exchange Commission requirements, our estimates of proved reserves for the year ended 2012 are determined based on a historical 12-month average price as of the first day of each month during the fiscal year. Any significant variance from these prices and costs could greatly affect our estimates of reserves. In addition, proved undeveloped reserves locations to limited to those scheduled to be drilled within the next five years.

As of April 30, 2012, the majority of our holdings are undeveloped. Undeveloped, by their nature, are less certain. Recovery of undeveloped property requires significant capital expenditures and successful drilling operations. Additionally, as oil and gas commodity prices become lower, the quantity of economically recoverable proved reserves declines. The reserve data assumes that we will make significant capital expenditures to develop our reserves. We have prepared estimates of our natural gas and oil reserves and the costs associated with these reserves in accordance with industry standards. However, the estimated costs may not be accurate, development may not occur as scheduled, or the actual results may not be as estimated. We may not have, or be able to obtain, the capital we need to develop these proved reserves.

Actual natural gas and oil prices, future production, revenues, operating expenses, taxes, development expenditures and quantities of recoverable natural gas and oil reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of future net revenues set forth in this annual report. A reduction in natural gas and oil prices, for example, would reduce the value of proved reserves and reduce the amount of natural gas and oil that could be economically produced, thereby reducing the quantity of reserves. We may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues referred to in this annual report is the current market value of our estimated natural gas and oil reserves. In accordance with United States Securities and Exchange Commission requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any change in consumption by natural gas and oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses for the development and production of our natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the United States Securities and Exchange Commission to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor, nor does it reflect discount factors used in the marketplace for the purchase and sale of oil and gas properties. Conditions in the oil and gas industry and oil and gas prices will affect whether the 10% discount factor accurately reflects the market value of our estimated reserves.

We are subject to the full cost ceiling limitation and may result in a write-down of our estimated net reserves in the future.

We utilize the full cost method of accounting for costs related to our natural gas and oil properties. Under the full cost method, we are subject to quarterly calculations of a "ceiling" or limitation on the amount of our oil and gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and gas properties exceed the cost center ceiling, we are subject to a write-down of our net oil and gas properties to the extent of such excess. A capitalized cost ceiling test impairment also reduces earnings and impacts stockholders' equity in the period of occurrence and results in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments.

We impaired $8.3 million of our property subject to amortization due to this ceiling test. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when natural gas and crude oil prices are depressed or volatile. In addition, a write-down of proved oil and natural gas properties may occur if we experience substantial downward adjustments in our estimated proved reserves, or if purchasers cancel long-term contracts for our natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the applicable ceiling in the subsequent period. This and other factors could cause us to write down our natural gas and oil properties or other assets in the future and incur a non-cash charge against future earnings.

Competition in the oil and natural 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.

We operate in highly competitive areas of oil and natural gas exploration, development and acquisition with a substantial number of other companies. We face intense competition from independent, technology-driven companies, as well as from both major and other independent oil and gas companies, in each of the following areas:

•	acquiring desirable producing properties or new leases for future exploration;
•	marketing our natural gas and oil production;

•	integrating new technologies; and
•	acquiring the equipment, personnel and expertise necessary to develop and operate our properties.

Many of our competitors have financial, managerial, technological and other resources substantially greater than ours. These companies may be able to pay more for exploratory prospects and productive oil and gas properties, and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. To the extent our competitors are able to pay more for properties than we are, we will be at a competitive disadvantage. Further, many of our competitors may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties, and consummate transactions in this highly competitive environment.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs), and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations, or subject us to administrative, civil and criminal penalties, including the assessment of natural resources damages. Environmental and other governmental laws and regulations also increase the costs to plan, permit, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. Compliance costs are significant. The exploration and production of oil and gas involves many risks concerning equipment and human operational problems that could lead to leaks or spills of petroleum products. These laws and regulations, particularly in the Rocky Mountain regions, are extensive and involve severe penalties and could change in ways that substantially increase our costs and associated liabilities.

Part of the regulatory environment in which we operate includes, in some cases, federal and state requirements for performing or preparing environmental assessments, environmental impact statements, studies, reports and/or plans of development before commencing exploration and production activities. These regulations affect our operations and may hinder or limit the quantity of oil and natural gas we may be able to produce and sell.

A major risk inherent in our drilling plans is the need to obtain drilling permits from applicable federal, state and local authorities. Delays in obtaining regulatory approvals or drilling permits for producing and water injection wells, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore or develop our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating area. Any or all of these contingencies could delay or halt our drilling activities or the construction of ancillary facilities necessary for production, which would prevent us from developing our property interests as planned. Conditions, delays or restrictions imposed on the management of groundwater produced during drilling could severely limit our operations or make them uneconomic.

We cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. For example, matters subject to regulation and the types of permits required include:

•	drilling permits;
•	water discharge and disposal permits for drilling operations;
•	the amounts and types of substances and materials that may be released into the environment;
•	drilling and operating bonds;
•	environmental matters and reclamation;
•	spacing of wells;
•	the use of underground injection wells, which affects the disposal of water from our wells;
•	occupational safety and health;
•	unitization and pooling of properties;
•	air quality, noise levels and related permits;
•	rights-of-way and easements;
•	reports concerning operations to regulatory authorities;
•	calculation and payment of royalties;
•	gathering, transportation and marketing of gas and oil;
•	taxation; and
•	waste disposal.

Under these laws and regulations, we could be liable for:

•	personal injuries;
•	property damage;
•	oil spills;
•	discharge or disposal of hazardous materials;
•	well reclamation costs;
•	surface remediation and clean-up costs;
•	fines and penalties;

•	natural resource damages; and
•	other environmental protection and damages issues.

Changes in applicable laws and regulations could increase our costs, reduce demand for our production, impede our ability to conduct operations or have other adverse effects on our business.

Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us. For example, the Environmental Protection Agency (“EPA”) has issued a notice of finding and determination that emissions of carbon dioxide, methane and other greenhouse gases ("GHG") present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has recently begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress is considering "cap and trade" legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs.

Additionally, the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Reform Act, among other things, imposes restrictions on the use and trading of certain derivatives, including energy derivatives. The nature and scope of those restrictions will be determined in significant part through implementing regulations to be adopted by the United States Securities and Exchange Commission, the Commodities Futures Trading Commission and other regulators. If, as a result of the Reform Act or its implementing regulations, additional capital or margin requirements or other limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability to implement our hedging strategy.

In addition, some of our activities involve the use of hydraulic fracturing, which a process that creates a fracture is extending from the wellbore in a rock formation to enable oil or natural gas to move more easily through the rock pores to a production well. Fractures are typically created through the injection of water and chemicals into the rock formation. Legislative and regulatory efforts at the federal level and in some states have been made to render permitting and compliance requirements more stringent for hydraulic fracturing. These proposals, if adopted, would likely increase our costs and make it more difficult, or impossible, to pursue some of our development projects.

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

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future success depends on our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when production occurs unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We may not be able to find, develop or acquire additional reserves on an economic basis. Furthermore, if oil and natural gas prices increase, our costs for additional reserves could also increase. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find, finance or acquire additional reserves to replace our current and future production at acceptable costs.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and expenses, and drilling and production results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled, or if we will be able to produce natural gas or oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

We may be affected by climate change and market or regulatory responses to climate change.

Climate change, including the impact of global warming, could have a material adverse effect on our results of operations, financial condition, and liquidity. Restrictions, caps, taxes, or other controls on emissions of greenhouse gasses, including exhaust from generators, engines and flaring of excess natural gas, could significantly increase our operating costs. Restrictions on emissions could also affect our customers that (a) use oil and gas to produce energy, or (b) manufacture or

produce goods that consume significant amounts of energy or burn fossil fuels, including chemical producers, farmers and food producers, and automakers and other manufacturers. Significant cost increases, government regulation, or changes of consumer preferences for goods or services relating to alternative sources of energy or emissions reductions could materially affect the markets for the oil and gas commodities, which in turn could have a material adverse effect on our results of operations, financial condition, and liquidity. Government incentives encouraging the use of alternative sources of energy could also affect certain of our oil and gas commodity purchasers and the markets for certain of the commodities in an unpredictable manner, including, for example, the impacts of ethanol incentives on farming and ethanol producers and tax credits for wind turbine and solar power generation. Finally, we could face increased costs related to defending and resolving legal claims and other litigation related to climate change and the alleged impact of our operations on climate change. Any of these factors, individually or in operation with one or more of the other factors, or other unforeseen impacts of climate change could reduce the demand for oil and gas commodities and have a material adverse effect on our results of operations, financial condition, and liquidity.

The loss of key personnel could adversely affect our business.

We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of the services of these or other key personnel could adversely affect our business, and we do not maintain key man insurance on the lives of many of these persons.

We depend to a large extent on the efforts and continued employment of our chief executive officer, chief financial officer, chief operating officer, and our vice president of geology, and other key management and technical personnel.

Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.

We do not insure against all potential operating risks. We may incur substantial losses and be subject to substantial liability claims as a result of various lawsuits.

We are not insured against all risks. We ordinarily maintain insurance against various losses and liabilities arising from our operations in accordance with customary industry practices and in amounts that management believes to be prudent. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations. Business disruptions could seriously harm our future revenue and financial condition and increase our costs and expenses. Our operations could be subject to earthquakes, power shortages, telecommunications failures, water shortages, floods, hurricanes, extreme weather conditions and other natural or manmade disasters or business interruptions, for which we are predominantly self-insured. The occurrence of any of these business disruptions could seriously harm our revenue and financial condition and increase our costs and expenses. Our natural gas and oil exploration and production activities are subject to numerous hazards and risks associated with drilling for, operating, producing and transporting natural gas and oil, and any of these risks can cause substantial losses resulting from:

•	environmental hazards, such as uncontrollable flows of natural gas, oil, brine water, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
•	abnormally pressured formations and ground subsidence;
•	mechanical difficulties, inadequate oil field drilling and service tools, and casing collapses;
•	fires and explosions;
•	personal injuries and death;
•	labor and employment;
•	regulatory investigations and penalties; and
•	natural disasters, such as earthquakes, hurricanes and floods.
•	shortages in drilling equipment or personnel.

Any of these risks could have a material adverse effect on our ability to conduct operations or result in substantial losses to us. Many of these risks are not insured as the cost of available insurance, if any, is excessive. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs that is not fully covered by insurance, it could have a material adverse effect on our business, financial condition and results of operations.

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 plans.

If domestic drilling activity increases, particularly in the fields in which we operate a general shortage of drilling and completion rigs, field equipment and qualified personnel could develop. As a result, the costs and delivery times of rigs, equipment and personnel could be substantially greater than in previous years. From time to time, these costs have sharply increased and could do so again. The demand for and wage rates of qualified drilling rig crews generally rises in response to the increasing number of active rigs in service and could increase sharply in the event of a shortage. Shortages of drilling and completion rigs, field equipment or qualified personnel could delay, restrict or curtail our exploration and development operations, which could in turn harm our operating results.

Increases in taxes on energy sources may adversely affect the company's operations.

Federal, state and local governments which have jurisdiction in areas where the company operates impose taxes on the oil and natural gas products sold. Historically, there has been an on-going consideration by federal, state and local officials concerning a variety of energy tax proposals. Such matters are beyond the company's ability to accurately predict or control.

Risks Relating to Ownership of Our Common Stock

The number of shares eligible for future sale or which have registration rights could adversely affect the future market for our common stock.

Sales of substantial amounts of previously restricted shares of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline, or could impair our ability to raise capital through the sale of additional common or preferred stock.

As of July27, 2012, we had41,193,670 shares of common stock outstanding. Our directors, executive officers, and stockholders holding more than 10% of our outstanding common stock have significant holdings.

If our stockholders sell significant amounts of common stock in any public market that develops or exercise their registration rights and sell a large number of shares, the price of our common stock could be negatively affected. If we were to include shares held by those holders in a registration statement pursuant to the exercise of their registration rights, those sales could impair our ability to raise needed capital by depressing the price at which we could sell our common stock or impede such an offering altogether.

Our stock price has been and may be volatile, and your investment in our stock could decline in value.

In recent years, the stock market has experienced significant price and volume fluctuations. Our common stock has and may experience volatility unrelated to our operating performance for reasons that include:

•	Domestic and worldwide supplies and prices of and demand for natural gas and oil;
•	Needs and motivations of stockholders of a personal nature;
•	Political conditions in natural gas and oil producing regions;
•	The success of our operating strategy;
•	War and acts of terrorism;
•	Demand for our common stock;
•	Revenue and operating results failing to meet the expectations of securities analysts or investors in any particular quarter or period;
•	Changes in expectations of our future financial performance, or changes in financial estimates, if any, of public market analysts;
•	Investor perception of our industry or our prospects;
•	General economic trends;
•	Limited trading volume of our stock;
•	Changes in and compliance with environmental and other governmental rules and regulations;
•	Actual or anticipated quarterly variations in our operating results;
•	Our involvement in litigation;
•	Conditions generally affecting the oil and natural gas industry;
•	The prices of oil and natural gas;
•	Announcements relating to our business or the business of our competitors;
•	Our liquidity; and
•	Our ability to obtain or raise additional funds.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

We have not paid cash dividends on our common stock and do not anticipate paying any dividends on our common stock in the foreseeable future.

We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our operating results, financial conditions, current and anticipated cash needs and plans for expansion.

We make estimates and assumptions in connection with the preparation of Sun River's Consolidated Financial Statements, and any changes to those estimates and assumptions could have a material adverse effect on our results of operations.

In connection with the preparation of Sun River's Consolidated Financial Statements, we use certain estimates and assumptions based on historical experience and other factors. Our most critical accounting estimates are described in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report. In addition, as discussed in Note A to the Consolidated Financial Statements, we make certain estimates, including decisions related to provisions for legal proceedings and other contingencies. While we believe that these estimates and assumptions are reasonable under the circumstances, they are subject to significant uncertainties, some of which are beyond our control. Should any of these estimates and assumptions change or prove to have been incorrect, it could have a material adverse effect on our results of operations.

Failure of the Company's internal control over financial reporting could harm its business and financial results.

The management of Sun River is responsible for establishing and maintaining effective internal control over financial reporting. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes maintaining records that in reasonable detail accurately and fairly reflect the Company's transactions; providing reasonable assurance that transactions are recorded as necessary for preparation of the financial statements; providing reasonable assurance that receipts and expenditures are made in accordance with management authorization; and providing reasonable assurance that unauthorized acquisition, use or disposition of the Company assets that could have a material effect on the financial statements would be prevented or detected on a timely basis. Because of its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of the Company's financial statements would be prevented or detected. Failure to maintain an effective system of internal control over financial reporting could limit the Company's ability to report its financial results accurately and timely or to detect and prevent fraud.

ITEM 1B - UNRESOLVED STAFF COMMENTS.

None

ITEM 3 - LEGAL PROCEEDINGS

Ballard Litigation

On June 7, 2012, James Ballard, Iva Ballard, John Dein, M.D., Ginger “Gigi” Toupal, William “Bruce” Pitts, Steven R. Henson, M.D., David K. Henson and Colin Richardson filed a lawsuit in the 134th district court in Dallas County, Texas. The defendants in the lawsuit are Sun River Energy, Inc., Donal R. Schmidt, Jr., Robert B. Fields, Stephen W. Weathers, Thimothy S. Wafford, Daniel M. Cofall, Judson “Rick” Hoover, Mark Hall, Penny Schmidt, Sierra Foxtrot, LP, and Sierra Foxtrot GenPar, LLC. The Plaintiffs allege breach of fiduciary duty, fraud, negligent misrepresentation, statutory fraud, violations of the Texas Securities Act, breach of contract, civil conspiracy, defamation, and fraudulent transfer. The Plaintiffs purport to bring a shareholder derivative action on behalf of the Company seeking damages for the Company against each of the directors and several officers. At the same time, the Plaintiffs seek to recover damages against the Company for the individual plaintiffs. The Plaintiffs failed to make demand upon the Company’s board of directors prior to filing the derivative action, and failed to comply with other legal requirements (such as making demand upon the Company’s shareholders) prior to initiating such action. The Company denies the allegations, does not believe the lawsuit is meritorious and has filed a motion to dismiss the lawsuit. The Company is also seeking to recover its attorneys’ fees from the plaintiffs, as allowed by law.

BPC Litigation

On June 28, 2012, BPC Corp. (“BPC”) filed a lawsuit in the County Court at Law No. 3 in Dallas, Texas against the Company and Sun River Energy I, LLC and Donal R. Schmidt, Jr. alleging that the defendants breached the terms of a written lease agreement and seeking to recover damages against the Company and the other defendants in connection with the same. BPC also alleges that the defendants committed various torts in connection with the alleged breach of the lease agreement. The defendants have filed a general denial of the allegations.

Nova Leasing Litigation

On March 18, 2011, Nova Leasing, LLC (“Nova”) filed a lawsuit in the U.S. District Court for the District of Colorado against the Company and Securities Transfer Corporation (“STC”) in connection with a dispute involving a series of transactions between Nova and the Company, wherein Nova received 1,200,000 shares of the Company’s stock. The stock was issued to Nova in connection with some oil and gas leases Nova assigned to the Company. In 2006, the Company issued the stock and a promissory note for approximately $6,000,000 to Nova. The Company paid approximately $1,000,000 to Nova, but couldn’t pay the remainder of the note, so the Company agreed to return all of the oil and gas leases to Nova. The Company entered into a release with Nova pursuant to advice from the Company’s previous general counsel. The Company believes that Nova agreed to return the stock to the Company, but it was never returned. In 2011, the Company discovered that its previous general counsel (who advised the Company in connection with the Nova transaction) was also a member of Nova Leasing, but this was not disclosed to the Company at the time of the transactions. The Company added the previous general counsel as a party to the lawsuit. In the lawsuit, the Company seeks the return of the 1,200,000 shares of stock, damages and attorneys’ fees from Nova based upon claims of rescission, unjust enrichment, fraud and breach of fiduciary duty. In the lawsuit, Nova seeks damages, and attorneys’ fees from the Company.

Coral Capital Partners, Erik Nelson, and Steve Stephens Litigation

On January 1, 2011, the Company filed a lawsuit against Coral Capital Partners, Erik Nelson and Steve Stephens in Denver, Colorado. This lawsuit involves Sun River’s refusal to remove a restrictive legend from approximately 125,000 shares of restricted stock issued to the defendants in connection with consulting services they were to perform for the Company. Sun River refused to lift the legend because the defendants failed to perform the services they agreed to provide the Company and based upon insider trading by Nelson. Sun River filed the suit to seek a declaratory judgment from the court regarding its obligations to remove the restrictive legend. This lawsuit was settled on terms whereby Nelson agreed to return to the Company all shares still in his possession (approximately 25,000 shares) and Stephens agreed to return to the Company all shares in his possession, except for 40,000 shares which the Company allowed him to retain. After the defendants agreed in writing to these terms, they reneged on the settlement. Recently, the Company filed a motion for summary judgment in an attempt to resolve the case without having to proceed to trial.

Cicerone Litigation

On February 10, 2012, the Company filed a claim against Cicerone Corporate Development, LLC and J.H. Brech, LLC, former consultants for the Company, the C.E. McMillan Trust and Harry McMillan, (the “Defendants”) for violations of Section 16(b) of the Securities Exchange Act of 1934, as amended (the “Act”), for profits realized by the Defendants from transactions involving the Company’s stock. The claim was filed as an adversary proceeding in the United States Bankruptcy Court, Northern District of Texas, Fort Worth Division. The Company is seeking to recover short-swing profits estimated to be equal to at least $4 million from the Defendants in connection with a number of transactions involving the Company’s stock. The Company is being represented in the litigation on a contingency basis to recover any short-swing profits from the Defendants. Under the contingent fee arrangement, the Company will not incur any out of pocket expenses or fees in connection with this matter.

ITEM 4 - RESCINDED AND REMOVED.

PART II

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

Our common stock is currently traded on the OTC Bulletin Board maintained by the Financial Industry Regulatory Authority (the "FINRA") under the symbol "SNRV." The following table sets forth the range of high and low bid quotations for our common stock of each full quarterly period during the two most recently completed fiscal years. The quotations were obtained from information published by FINRA and reflect interdealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

The Quarter Ended	HIGH		LOW

April 30, 2012	$	.99	$	.22
January 31, 2012		2.60		.54
October 31, 2011		4.15		1.92
July 31, 2011		5.17		4.25

The Quarter Ended	HIGH		LOW

April 30, 2011	$	5.15	$	4.35
January 31, 2011		4.25		2.05
October 31, 2010		2.06		1.41
July 31, 2010		1.80		1.30

As of April 30, 2012, there were an estimated 596 holders of record of our common stock, exclusive of objecting beneficial owners (individuals who deposit shares with a broker and don’t wish to provide to the Company personal information).

Dividends

To date, we have not paid any dividends on our common stock nor established a policy concerning payment of Common Stock dividends. Any payment of dividends in the future will be determined by the Board of Directors in light of conditions then existing, including restrictions imposed by our preferred stock then outstanding, if any, our earnings, financial condition, capital requirements and debt covenants, if any, and the tax treatment of any such dividends.

Unregistered Sales of Equity

The Company made the following unregistered sales of its securities from February 28, 2012 to June 30, 2012.

Date of Sale	Title of Securities	Number of Shares	Consideration	Class of Purchaser
05/1/2012 through 06/20/2012	Common Stock	3,490,000	Exchange of options	Officers, Directors and employees
5/2/2012 through 5/4/2012	Common Stock	308,337	Consulting services	Consultants
2/11/2012 through 05/31/2011	Common Stock	299,999	Services	Officers, Directors and employees
6/15/2012 through 6/30/2012	Common Stock	650,000	Cash	Stockholders

Exemption from Registration Claimed

All of the shares described above were issued by us in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, provided by Section 4(2). All of the individuals and/or entities listed above that purchased the unregistered securities were all known to us and our management, through pre-existing business relationships, as long standing business associates, friends, and employees. All purchasers were provided access to all material information, which they requested, and all information necessary to verify such information and were afforded access to our management in connection with their purchases. All purchasers of the unregistered securities acquired such securities for investment and not with a view toward distribution, acknowledging such intent to us. All certificates or agreements representing such securities that were issued contained restrictive legends, prohibiting further transfer of the certificates or agreements representing such securities, without such securities either being first registered or otherwise exempt from registration in any further resale or disposition.

ITEM 6 – SELECTED FINANCIAL DATA

Not Applicable

ITEM 7 – MANAGEMENT DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONAND RESULTS OF OPERATIONS

CAUTIONARY AND FORWARD LOOKING STATEMENTS

In addition to statements of historical fact, this Annual Report on Form 10-K for the years ended April 30, 2012 and 2011 contains forward-looking statements. The presentation of future aspects of Sun River Energy, Inc. ("Sun River," the "Company" or "issuer") found in these statements is subject to a number of risks and uncertainties that could cause actual results to differ materially from those reflected in such statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which reflect management's analysis only as of the date hereof. Without limiting the generality of the foregoing, words such as "may," "will," "expect," "believe," "anticipate," "intend," or "could" or the negative variations thereof or comparable terminology are intended to identify forward-looking statements.

These forward-looking statements are subject to numerous assumptions, risks and uncertainties that may cause the Company's actual results to be materially different from any future results expressed or implied by the Company in those statements. Important facts that could prevent the Company from achieving any stated goals include, but are not limited to, the following:

Some of these risks might include, but are not limited to, the following:

•	volatility of the Company's stock price;
•	potential fluctuation in quarterly results;

•	failure of the Company to earn revenues or profits;
•	inadequate capital to continue or expand its business, inability to raise additional capital or financing to implement business plans;

•	failure to commercialize its technology or to make sales;
•	rapid and significant changes in markets;

•	litigation with or legal claims and allegations by outside parties; and
•	insufficient revenues to cover operating costs.

The Company undertakes no obligation to publicly revise these forward-looking statements to reflect events or circumstances that arise after the date hereof. Readers should carefully review the factors described in other documents the Company files, from time to time, with the United States Securities and Exchange Commission, including the Quarterly Reports on Form 10-Q and any Current Reports on Form 8-K filed by the Company.

Plan of Operations

We began generating revenues during the year ended April 30, 2011. We have net working capital deficit as of April 30, 2012and 2011of approximately $13,918,000 and $6,492,000, respectively. The primary source of funds for the Company during 2012 was generated by issuance of common stock, preferred stock, and debt. During 2011 the primary sources of funds were derived from the sale of preferred stock. We have sold some of the Company’s hard rock mineral rights after our year end for approximately $500,000 and 2,564,103 shares of the purchaser’s common stock. We will continue to pursue monetizing the Company’s mineral assets. We will need substantial additional capital to support any future operations. We have no committed source for any funds necessary to meet the investment requirements reflected in the reserve report. Future funding is anticipated to be primarily from debt and equity funding. These funds will be primarily utilized for working capital and expansion. No representation is made that any funds will be available when needed.

Results of Operations – Year Ended April 30, 2012 Compared To Year Ended April 30, 2011

During the year ended April 30, 2011 the Company began generating revenues. We generated $293,000 in revenues, during 2012 as compared to $98,000in the prior year an increase of $195,000 or 200% increase. We anticipate revenues in the coming year to decline unless there is substantial investment in the company’s assets and increases in commodity prices. Our current revenues are limited by the number of wells we have producing. Any problem with a single well can generate significant variances in our revenues.

During the year ended April 30, 2012, the Company incurred general and administrative expenses of $14,385,000 compared to $7,682,000 during the year ended April 30, 2011. The increase of $6,703,000 or 87% was primarily a result of increases in direct employee expenses of $7,089,000 including $4,026,000 for costs associated with the fair value of equity issued. Directors’ fees paid in cash, of $247,000 as compared to $66,000 during the year ended April 30, 2011, an increase of 276%.

During the year 2012, the Company took an impairment charge to their oil and gas properties of $8,454,000. The charge is primarily due to a lack of available investment capital as commodity prices remain low, and low commodity prices.

During the year ended 2012, the Company took an impairment charge for $287,000 to goodwill, primarily due to lower commodity prices generated reduced operational opportunities to generate revenue.

During the year ended April 30, 2012, the Company recognized a net loss of $24,047,000 compared to a net loss of $7,328,000 during the year ended April 30, 2011 an increase in the loss of $16,719,000 or 228%.

Liquidity and Capital Resources

At April 30, 2012, the Company had total current assets of $145,000, a decrease of approximately $1,651,000 from 2011. The total current liabilitiesof $14,063,000consists primarily of notes payable, and accounts payable to related parties totaling $10,419,000. Total current liabilities increased $5,775,000, or 70% over 2011. The Company has raised over $2.8 million in cash from aequity and debt offerings. The Company continues to raise capital to fund current operations.

The Company does not have capital sufficient to meet its operating or investment needs. The Company will have to seek equity placements or debt to cover such cash needs.

No commitments to provide additional funds have been made by the Company's management or other stockholders. Accordingly, there can be no assurance that any additional funds will be available to the Company to allow it to expand the Company's asset base.

Critical Accounting Policies and Estimates

Recent Accounting Pronouncements

For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see Note 1 to the Company’s consolidated financial statements included in Item 8 of this report.

Oil and Gas Properties, Full Cost Method

The Company uses the full cost method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells used to find proved reserves, and to drill and equip development wells including directly related overhead costs and related asset retirement costs are capitalized.

Under this method, all costs, including internal costs directly related to acquisition, exploration and development activities are capitalized as oil and gas property costs. Properties not subject to amortization consist of exploration and development costs which are evaluated on a property-by-property basis. Amortization of these unproved property costs begins when the properties become proved or their values become impaired. The Company assesses the realization of unproved properties, taken as a whole, if any, on at least an annual basis or when there has been an indication that impairment in value may have occurred. Impairment of unproved properties is assessed based on management’s intention with regard to future exploration and development of individually significant properties and the ability of the Company to obtain funds to finance such exploration and development. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Costs of oil and gas properties will be amortized using the units of production method.

In applying the full cost method, the Company will perform an impairment test (ceiling test) at each reporting date, whereby the carrying value of property and equipment is compared to the “estimated present value,” of its proved reserves discounted at a 10-percent interest rate of future net revenues, based on a look back at the average cost for the commodity at the first of the month for the prior 12 months. plus the cost of properties not being amortized, plus the lower of cost or fair market value of unproved properties included in costs being amortized, less the income tax effects related to book and tax basis differences of the properties. If capitalized costs exceed this limit, the excess is charged as an impairment expense.

Stock-Based Compensation

In March of 2012 the Company’s Board of Directors voted to allow Officers, Directors and employees who were holding options to purchase shares of the Company’s common stock to exchange those options for shares of the Company’s common stock on a ratio of 1:1. The unamortized portion of the value of the options issued was expensed and the value of the shares on the date of election was recorded as a modification to the agreement.

Impairment of Long-Lived Assets

All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than its future net cash flows. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil, NGLs and gas, future costs to produce these products, estimates of future oil and gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test an asset for impairment may result from significant declines in commodity prices or downward revisions to estimated quantities of oil and gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded.

For April 30, 2012, we recorded an impairment expense of $8.6 million, of which $8.3 million was attributable to our oil and gas properties in Texas.

At April 30, 2012, we had $155,000 recorded for Texas, which is the estimated fair value at April 30, 2012. We also recorded an impairment expense of $286,000, related to all of our remaining carrying costs associated with our goodwill, which was the total carrying value we had recorded.

Changes in Internal Control over Financial Reporting.

There were no changes in internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. During the course of the audit, a weakness in Internal Control was identified in that the company was failing to follow its written policy regarding expense reimbursement. Management has taken steps to correct this weakness.

ITEM 9B – OTHER INFORMATION

Not Applicable

PART III

ITEM 10 – DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

See "Executive Officers, Board of Directors, Committees of the Board and Section 16(a) Beneficial Ownership Reporting Compliance" in the Sun River Energy, Inc. Proxy Statement ("Proxy Statement"), for the Annual Meeting of Stockholders of Sun River Energy, Inc. to be announced (to be filed with the United States Securities and Exchange Commission within 120 days after the end of the Company's fiscal year ended April 30, 2012) which is incorporated herein by reference.

The Company's Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer (Code of Ethics) can be found on the Company's internet website located at www.snrv.com. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company intends to disclose the information on its internet website. This information will remain on the website for at least 12 months.

ITEM 11 – EXECUTIVE COMPENSATION

Information required by this item will be contained in the Proxy Statement under the caption "Executive Compensation," and is hereby incorporated by reference herein.

ITEM 12 – SECURITIES OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this item will be contained in the Proxy Statement under the caption "Securities Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" and is incorporated herein by reference.

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

Information required by this item will be contained in the Proxy Statement under the caption "Certain Transactions" and "Corporate Governance" and is hereby incorporated by reference herein.

ITEM 14 –PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by this item will be contained in the Proxy Statement under the caption "Auditors' Fees," and is hereby incorporated by reference "Regulations and Environmental Matters" and "—Future Regulations" herein.

PART IV

ITEM 15 – EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

The following is a complete list of exhibits filed as part of this Form 10K. Exhibit number corresponds to the numbers in the Exhibit table of Item 601 of Regulation S-K.

Exhibit No.	Exhibit Description		Incorporated by Reference
		Form	SEC File	Exhibit	Filing Date	Filed Herewith
3.1(i)		10-SB12G	000-27485	3.1(i)	9/29/1999

3.2	Articles of Incorporation.	10-Q	000-27485	3.2	3/11/2011

4.1	Certificate of Designation of 8%	10-Q	000-27485	4.1	3/11/2011
	Series A Cumulative Convertible
	Preferred Stock

4.2	Warrants issued to J.HBrech	10-Q	000-27485	4.2	3/11/2011

4.3	Warrant issued to Tom Anderson	10-Q	000-27485	4.3	3/11/2011


4.4	Warrant issued to Redgie Green	10-Q	000-27485	4.4	3/11/2011

4.5	Warrant issued to David Surginer	10-Q	000-27485	4.5	3/11/2011

	Warrant issued to Steven Weathers

4.6	Warrants issued to Cicerone Corporate Development	10-Q	000-27485	4.6	3/11/2011

4.7	Warrant issued to Avalon	10-Q	000-27485	4.7	3/11/2011

4.8	Warrant issued to Aspenwood Capital	10-Q	000-27485	4.8	3/11/2011

21	List of subsidiaries

23.1	Consent of Independent Petroleum Consultants

31.1	Rule 13a-14(a) Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					*

31.2

Rule 13a-14(a) 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 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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.

	SUN RIVER ENERGY, INC.

Date: August 15, 2012	By:	/s/ Donal R. Schmidt, Jr.
	Donal R. Schmidt, Jr. Chief Executive Officer and President
	(Principal Executive)
Date: August 15, 2012	By:	/s/ J F Hoover
	J. F. Hoover, Chief Financial Officer (Principal Financial and
	Accounting 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.

Date: : August 6, 2012	By:	/ s/Donal R. Schmidt, Jr.
	Donal Schmidt, Chief Executive Officer, President and Chairman of the Board
	(Principal Executive)

Date: August 15, 2012	By:	/s/ J F Hoover
	J. F. Hoover, Chief Financial Officer (Principal Financial and Accounting Officer)

Date: August 15, 2012	By:	/s/Robert B. Fields
	Robert B. Fields and Director

Date: August 15, 2012	By:	/s/Dan Cofall
	Dan Cofall, Director

Date: August 15, 2012	By:	/s/ Stephen W. Weathers
	Stephen W. Weathers, Director

Date: August 15, 2012	By: /s/ Mark A. Hall
	Mark A. Hall, Director

PART I—FINANCIAL INFORMATION

Item 1.Financial Statements.

SUN RIVER ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS


	Page
Report of Independent Registered Public Accounting Firms		F-2

Consolidated Balance Sheets as of April 30, 2011 and 2010		F-3

Consolidated Statements of Operations for the Years Ended April 30, 2011and 2010		F-4

Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended April 30, 2011 and 2010		F-5

Consolidated Statements of Cash Flows for the Years Ended April 30, 2011 and 2010		F-6

Notes to Consolidated Financial Statements		F-7

Report of Independent Registered Public Accounting Firms

To the Board of Directors and Stockholders of Sun River Energy, Inc.

We have audited the accompanying consolidated balance sheet of Sun River Energy, Inc. (the “Company”) as of April 30, 2012, and the related consolidated statements of operations, cash flows, and stockholders' equity (deficit) for the year then ended. The financial statements for the year ended April 30, 2011, were audited by other auditors whose report expressed an unqualified opinion on those statements. The financial statements for the period May 1, 2010, through April 30, 2011, insofar as it relates to amounts for prior periods through April 30, 2011, is based solely on the report of other auditors. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sun River Energy, Inc. as of April 30, 2012, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has an accumulated earnings deficit of $41,027,526. This issue raises substantial doubt about its ability to continue as a going concern. Management’s plans in regards to these matters are also described in Note 1. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/S/ LIGHTFOOTGUESTMOORE&CO,P.C.

LIGHTFOOTGUESTMOORE&CO,P.C.

August 15, 2012

Dallas, TX

To the Shareholders and Board of Directors of

Sun River Energy, Inc.

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Sun River Energy, Inc. (the “Company”) as of April 30, 2011 and 2010, and the related consolidated statements of operations, cash flows, and stockholders' equity (deficit) 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 consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits include 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 Sun River Energy, Inc. as of April 30, 2011 and 2010, 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.

/s/ LBB & Associates Ltd., LLP

LBB & Associates Ltd., LLP

June 15, 2011

Houston, TX

Sun River Energy, Inc.	April 30,			April 30,
Consolidated Balance Sheets	2012			2011
(in thousands)
Assets
Current assets
Cash and cash equivalents	$	128		$	1,489
Accounts receivable, net		17			307
Total current assets		145			1,796
Oil and gas properties—net, based on full cost method of accounting:
Property subject to amortization		155			7,492
Property not evaluated and not subject to amortization		12,527			11,895
Furniture, fixtures, and equipment, net		78			145
Goodwill					287
Deposits					15
Total assets	$	12,905		$	21,630
Liabilities and stockholders' equity (deficit)
Current liabilities
Accounts payable and accrued expenses	$	3,045		$	1,050
Accrued expenses – related parties		6,194			2,131
Asset retirement obligations – current		125			19
Notes payable		474			88
Notes payable – related party		4,225			5,000
Total current liabilities		14,063			8,288
Asset retirement obligations, net of current portion		3			39
Total liabilities		14,066			8,327
Commitments and contingencies
Stockholders’ equity (deficit)
Preferred Stock, 8,750,000 shares authorized, par value $.01 no shares issued and outstanding at April 30, 2011 and 2010, respectively		--			--
8% Series A cumulative convertible preferred stock, par value $.01; authorized 1,250,000 shares, 251,000 and 0 shares issued as of April 30, 2011 and 2010, respectively.		1			3
Common stock — $.0001 par value; authorized, 100,000,000 shares; 33,562,369 shares and 27,946,898 at April 30, 2012 and 2011, respectively.		3			3
Additional paid-in-capital		39,862			30,277
Accumulated deficit		(41,027	)		(16,980	)
Total stockholders’ deficit		(1,161	)		13,303
Total liabilities and stockholders' deficit	$	12,905		$	21,630
The accompanying notes are an integral part of these consolidated financial statements.

SUN RIVER ENERGY
Consolidated Statements of Operations
(in thousands, except for share data)

		For the years ended April 30,
		2012			2011

Revenues	$	293		$	98
Operational expenses:
Lease operating expense		392			38
Production taxes		26			7
Impairment of oil and gas properties		8,299			-
Impairment of goodwill		287
Depreciation, depletion and amortization		185			130
General and administrative		14,385			7,682

Total operational expenses		23,574			7,857

Net loss from operations		(23,281	)		(7,759	)

Other income (expense)
Interest expense		(766	)		(119	)
Gain on settlement of litigation					550
Total other income (expense)		(766	)		431

Net loss		(24,047	)		(7,328	)
Less dividends on preferred shares					26

Net loss applicable to common stockholders	$	(24,047	)	$	(7,354	)

Per share information
Net loss per common share
Basic and diluted	$	(0.76	)	$	(0.32	)
Weighted average number
of common stock outstanding		31,565,766			23,125,517

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

SUN RIVER ENERGY, INC.

(in thousands, except for share data)

Consolidated Statements of Stockholder’s Equity (Deficit)

For the years ended April 30, 2011 and 2012

(In thousands, except for share data)

	Common Stock			Preferred Stock
	# of Shares	Amount		# of Shares		Amount		Additional Paid-in Capital		Accumulated Deficit		Common Stock delivered in advance of debt settlement		Total Stockholders’ equity (deficit)
Balance - April 30, 2010 (as restated	19,373,995		2		-		-		7,416		(9,654)		(470)		(2,704)

Issuance of stock for conversion of notes payable and interest	2,189,732		-		-		-		1,802		-		-		1,802
Issuance of stock for oil and gas properties, and equipment	3,508,667		1		-		-		10,226		-		-		10,227
Issuance of stock for services	615,000		-		-		-		1,078		-		-		1,078
Issuance of stock for cashless warrant exercise	244,004		-		-		-		-		-		-		-
Issuance of warrants for services	-				-		-		1,237		-		-		1,237
Issuance of preferred stock for cash	-		-		452,550		5		8,542		-		-		8,547
Dividends paid	-								(26)		-		-		(26)
Conversion of preferred stock to common stock	2,015,500		-		(201,550)		(2)		2		-		-		-
Settlement of debt for which stock was transferred in prior year	-		-		-		-		-		-		470		470
Net loss for period											(7,328)		-		(7,328)
Balance - April 30, 2011	27,946,898	$	3		251,000	$	3	$	30,277	$	(16,980)	$	-	$	13,303

Issuance of stock for conversion of notes payable and interest	720,000								1,087						1,087
Issuance of stock for oil and gas properties, and equipment
Issuance of stock for services	657,571								1,723						2,277
Issuance of common stock for cash	1,694,655
Issuance of equity for services									6,773						6,773
Issuance of preferred stock for cash
Dividends paid in stock	58,745
Conversion of preferred stock to common stock	2,484,500				(201,000)		(2)		2
Settlement of debt for which stock was transferred in prior year
Net loss for period											(24,047)				(24,047)
Balance - April 30, 2012	33,562,369	$	3		50,000	$	1	$	39,862	$	(41,027)	$	-	$	(1,161)

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

SUN RIVER ENERGY, INC.
Consolidated Statements of Cash Flows
(in thousands)
	For the Years Ended
	April 30,
	2012			2011

Cash flows from operating activities:
Net loss	$	(24,047	)	$	(7,328	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		67			130
Impairment of oil and gas properties		7,975			-
Impairment of goodwill		287			-
Equity issued for services		6,218			2,315
Gain on settlement of litigation		-			(550	)
Changes in current assets and liabilities:
Increase in accounts receivable		290			(307
Increase in accounts payable and accrued liabilities		6,314			3,173
Increase in deposits		15			(15	)
Net cash used in operating activities		(2,440	)		(2,582	)

Cash flows from investing activities:
Investment in oil and gas properties		(1,711	)		(4,478	)
Net cash used in investing activities		(1,711	)		(4,478	)

Cash flows from financing activities:
Preferred stock issued for cash		856			8,547
Proceeds from debt		625			466
Common stock issued for cash		1,322
Proceeds (payments) from advances					-
Payments on notes		(14	)		(478	)
Dividends paid					(26	)
Net cash provided by financing activities		2,789			8,509

Net (decrease) increase in cash		(1,362	)		1,449

Cash and cash equivalents — beginning of period		1,489			40

Cash and cash equivalents — end of period	$	128		$	1,489

Supplemental Disclosure of Cash Flow Information:
Cash paid for interest expense	$	5		$	5

Cash paid for income taxes	$	-		$	-

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

SUN RIVER ENERGY, INC. & SUBSIDIARIES

Notes to the Consolidated Financial Statements

Note 1 – Organization, Basis of Presentation and Summary of Significant Accounting Policies

Organization

Sun River Energy, Inc. is an exploration and production company focused on oil and natural gas. The Company’s strategy is to acquire acreage that allows it to predictably, consistently and profitably prove and develop these reserves. Senior management has demonstrated strength in identifying, acquiring, drilling, developing, producing and ultimately divesting unconventional natural gas resources.

As of April 30, 2012 Sun River owns mineral interests in New Mexico and Texas

		Developed Acres (A)				Undeveloped Acres (A)				Total Acres
Location		Gross		Net		Gross		Net		Gross		Net


New Mexico			0		0		222,855		211,649		222,855		211,649
Texas			2,554		2,239		3,890		3,773		6,445		6,013
Total			2,554		2,239		226,745		215,422		229,300		217,662
(A)	Undeveloped acreage may be contained in acreage that is held by production, or has been unitized with acreage that is currently under production.

Sun River’s largest asset is its undeveloped acreage in the Raton Basin of Colfax County, New Mexico. The Company owns subsurface and timber rights in fee simple. As of April 30, 2012, the total rights approximate 222,855 gross acres.

On July 27, 2012, Sun River Energy, Inc. (the "Company") entered into a Contract for Sale (“Agreement”) with Mericol, Inc. (“Buyer”) to sell only its gold, silver, iron ore, copper and coal interests in Colfax County, New Mexico. The Company will retain all other mineral interests or mineral extracts and timber interests. The Company is also granting Buyer a three (3) year option to acquire a 5% working interest in any oil and/or gas (including coalbed methane) wells drilled on the Company’s lands. The Agreement has an effective date of July 27, 2012 (the “Effective Date”).

Under the terms of the Agreement, Buyer shall pay the Company the Purchase Price consisting of the following: (1) five hundred thousand dollars ($500,000) and (2) two million five hundred sixty four thousand one hundred and three (2,564,103) shares of Buyer’s common stock (the “Shares”), which shall be subject to a lock-up period of twelve (12) months.

Basis of Presentation

The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). References to GAAP issued by the Financial Accounting Standards Board (“FASB”) in these footnotes are to the FASB Accounting Standards Codification (“ASC”). The consolidated financial statements include the accounts of Sun River Energy, Inc. and its’ wholly owned subsidiaries. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All significant intercompany transactions have been eliminated.

Certain reclassifications have been made to the consolidated financial statements for prior periods in order to conform to the current period presentation.

Going concern considerations

During the years ended April 30, 2012 and 2011, the Company incurred losses of $24,047,000 and $7,328,000, respectively, and has negative working capital of $13,918,000 and $6,492,000 at April 30, 2012 and 2011 respectively. Approximately $10,419,000 of the negative working capital position was comprised of amounts owed to significant stockholders, including Officers of the Company. The Company is attempting to raise capital to resolve the working capital requirements and develop the oil and gas assets. To a limited degree, the Company is evaluating the sale of certain shallow mineral rights. The Company has multiple options available to meet the current financial obligations when due, summarized as follows:

	●	The Company is attempting to settlement of its $4,000,000 note payable - related party obligation with assignment of certain mineral rights that the Company was not anticipating to develop; and/or
	●	Sun River has raised capital in a Preferred Stock offering, and the Company is currently attempting to raise additional equity through the sale of additional common stock and will utilize any proceeds to improve their working capital; and/or

●

The Company may sell a portion of our mineral rights to improve our working capital, in addition to other selected current liabilities of the Company which may be due.

However, there can be no assurance that the Company will be able to execute any or all of the above contemplated transactions, which raises substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements were prepared assuming that the Company will continue as a going concern which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

Summary of Significant Accounting Policies

Cash and cash equivalents

We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit, which, at times, exceed federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.

Accounts receivable

Accounts receivable are recorded at the invoiced amount, or estimated sales based on production reports for product delivered to buyer, and do not bear any interest. We regularly review receivables to insure that the amounts will be collected and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no reserves for uncollectible amounts in the periods presented.

Oil and gas properties, full cost method

In applying the full cost method, the Company will perform an impairment test (ceiling test) at each reporting date, whereby the carrying value of full cost pool is compared to the “estimated present value,” of its proved reserves discounted at a 10-percent interest rate of future net revenues, based on current economic and operating conditions, If capitalized costs of the full-cost pool exceed this limit, the excess is charged as an impairment expense.

During the year 2012, the Company took an impairment charge to their oil and gas properties of $8,300,000. The charge is primarily due to a lack of available investment capital as commodity prices remain low, and low commodity prices.

Stock-based compensation

The Company currently provides for stock-based compensation in three ways. (1) Shares of the Company’s common stock, and stock options and are granted to certain employees under the Company’s Incentive Plan. (2) The issuance of common stock vested over a period of time. (3) The issuance of warrants to purchase the Company’s common stock, which are primarily granted to certain service providers, including a consultant pursuant to a consulting agreement. Stock-based compensation is measured at the grant date.

The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. Awards that vest only upon achievement of performance criteria are recorded only when achievement of the performance criteria is considered probable. We estimate the fair value of stock options using the Black-Scholes option pricing model. This model is highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards, the estimated volatility of our stock price, and the assessment of whether the achievement of performance criteria is probable. The fair value of stock awards is based on the quoted market price on the grant date.

Furniture, fixtures & equipment

Furniture, fixtures & equipment are recorded at cost. Depreciation is on a straight-line method using the estimated lives of the assets (3-15 years). Expenditures for maintenance and repairs are charged to expense.

Goodwill

We utilized multiple market approaches to estimate the fair value of goodwill. In developing these fair value estimates, there was considerable judgment involved, particularly in determining the valuation methodologies to utilize and the weighting of different valuation methodologies applied. Certain key assumptions included the future value of services and assets, market capitalization, implied control premium, income taxes, depreciation and amortization and forecasted operating results.

During the year ended 2012, the Company took an impairment charge for $287,000 to goodwill, primarily due to lower commodity prices generated reduced operational opportunities to generate revenue.

Asset retirement obligations

The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. When the liability is initially recorded, there is a corresponding increase in the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, either the obligation is settled at its recorded amount or a gain or loss is incurred and recognized. If costs rise more than what we have expected there could be additional charges in the future, however, we monitor the costs of the abandoned wells and we will adjust this liability if necessary.

Revenue recognition

Oil and gas revenues are recognized net of royalties when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

Production Costs

Production costs, including compressor rental and repair, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on our consolidated statements of operations.

Exploration expenses include dry hole costs, delay rentals, and geological and geophysical costs.

Lease operating costs / joint-interest billings

All direct costs associated with and necessary to operate a producing property billed at the working interest percentage of each working interest party.

Business combinations

We account for business combinations in accordance with ASC Topic No. 805 (“ASC 805 “), Business Combinations. This statement establishes principles and requirements for how an acquirer recognizes assets acquired, liabilities assumed and any non-controlling interests acquired.

Fair value of financial instruments

Accounting guidance establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. We incorporate a credit risk assumption into the measurement of certain assets and liabilities.

Management estimates

The preparation of consolidated financial statements in conformity with generally accepted accounting principles 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. Significant estimates included in the consolidated financial statements are: (1) oil revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes; (4) accrued assets and liabilities; (5) stock-based compensation; and (6) asset retirement obligations. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates. Actual results could differ from those estimates.

Impairment of Long-Lived Assets

For April 30, 2012, we recorded an impairment expense of $8.6 million, of which $8.3 million was attributable to our oil and gas properties in Texas.

At April 30, 2012, we had $155,000 recorded for Texas, which is the estimated fair value at April 30, 2012. We also recorded an impairment expense of $287,000, related to all of our remaining carrying costs associated with our goodwill, which was the total carrying value we had recorded.

Earnings per share

The Company reports earnings (loss) per share in accordance with ASC Topic 260-10, “Earnings per Share.”Basic earnings(loss) per share is computed by dividing income (loss) available to common shareholders by the weighted average number of common shares available. Diluted earnings (loss) per share is computed similar to basic earnings (loss) per share except that the denominator is increased to include the number of additional common shares that would have been outstanding if the potential common shares had been issued and if the additional common shares were dilutive.Diluted earnings(loss) per share has not been presented since the effect of the assumed conversion of warrants and debt to purchase common shares would have an anti-dilutive effect.

Recent accounting standards

In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The amended guidance changes several aspects of the fair value measurement guidance in ASC 820, Fair Value Measurement, further clarifying how to measure and disclose fair value. This guidance amends the application of the “highest and best use” concept to be used only in the measurement of fair value of nonfinancial assets, clarifies that the measurement of the fair value of equity-classified financial instruments should be performed from the perspective of a market participant who holds the instrument as an asset, clarifies that an entity that manages a group of financial assets and liabilities on the basis of its net risk exposure can measure those financial instruments on the basis of its net exposure to those risks, and clarifies when premiums and discounts should be taken into account when measuring fair value. The fair value disclosure requirements also were amended. The amendment is effective for the Company at the beginning of July 2012, with early adoption prohibited. The adoption of this amendment is not expected to materially affect the Company’s financial statements.

In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income which amended requirements for the presentation of other comprehensive income (OCI), requiring presentation of comprehensive income in either a single, continuous statement of comprehensive income or on separate but consecutive statements, the statement of operations and the statement of OCI. The amendment is effective for the Company at the beginning of fiscal year 2013 with early adoption permitted. The Company elected early adoption of the guidance, which had no impact on our financial statements as we have no elements of comprehensive income other than net loss.

Note 2 – Oil and Gas Properties, Leases and Mineral Rights

All of the Company’s oil and gas properties are located in the United States. The Company’s oil and gas properties consist of the following at April 30, 2012 (,000 omitted):

Proved Properties	Acquisition Costs		Development Costs		Depletion			Asset Retirement Costs		Total
Balance at April 30, 2011	$	4,551	$	2,944	$	(61)		$	58	$	7,337
Activity-May 1, 2011 to April 30, 2012		(4,551)		(2,792)		(64	)		70		(7,209)
Total	$	0	$	152	$	(125	)	$	128	$	155

Unevaluated Properties	Acquisition Costs		Development Costs		Impairment of Properties			Asset Retirement Costs		Total
Balance at April 30, 2010	$	999	$	-		(899	)	$	-	$	100
Activity-May 1, 2010 to April 30, 2011		11,795									11,795
Total at April 30, 2011	$	12,794		-	$	(899	)		-	$	11,895
Activity-May 1, 2011 to April 30, 2012		632									632
Total at April 30, 2012	$	13,462			$	(899	)			$	12,523

The Company has allocated the costs of its oil and gas properties acquired in 2011 based on its estimate of relative values of the proved and unevaluated portions of its leaseholds, and the costs associated with those properties.The properties presently classified as unevaluated will be evaluated in the future. The purchase price is subject to reallocation as management moves forward with its evaluation of the unevaluated property.

Note 3 – Acquisitions

Acquisition of PC Operating Texas Inc.

On August 3, 2010, the Company acquired all of the outstanding capital stock of PC Operating Texas Inc. (“PC Operating”), a Texas corporation, pursuant to the terms of a Securities Purchase Agreement among the Company, Donal R. Schmidt Jr. and Thimothy Wafford. The acquisition was accounted for as a purchase and the results of PC Operating’s operations are included in the accompanying consolidated financial statements from the date of acquisition. In connection with the acquisition of PC Operating, the Company issued a total of 250,000 shares of its restricted common stock, valued at $387,500 or $1.55 per share, which was the fair market value of the Company’s common stock on August 3, 2010, to the shareholders of PC Operating. Subsequently, the Company changed the name of PC Operating to Sun River Operating, Inc. Sun River Operating, Inc. is a full service oil and gas operating company, located in Dallas, Texas. It owns office equipment, software, furniture and personal property that allow it to conduct operations in multiple geographic areas.

The assets acquired and liabilities assumed were as follows as of the date of the transaction:


Fixed assets	$	146,000
Accounts payable		(45,000	)
Net assets acquired		101,000
Value of common stock		387,000
Goodwill	$	286,000

On August 3, 2010, the Company also acquired leasehold and wellbore interests from FTP Oil and Gas LP (“FTP”) in a transaction valued at $3,114,000 pursuant to the terms of a Purchase and Sale Agreement between the Company and FTP. In consideration for the acquisition, the Company issued an aggregate of 1,338,000 restricted shares of its common stock to FTP owned by Messrs. Schmidt and Wafford and a convertible note in the principal amount of $1,000,000.00 was issued to FTP. The secured convertible note has a term of one year, bears interest at the rate of 8.0% per annum, and is convertible into shares of the Company’s restricted common stock at a conversion rate of $1.50 per share. The convertible note is secured by the assets acquired as part of this transaction.

The acquisition of assets from FTP includes approximately 2,148 gross acres (1,610 net acres) in Tom Green County, Texas, which consists of four prospects. In addition, the Company acquired a 39% working interest of 29.25% net revenue interest in two wells on the acreage as described above. Additionally, FTP assigned to the Company its rights, title and interest in certain participation agreements and a surface use agreement. We allocated the entire purchase price to unevaluated properties.

On October 22, 2010, the Company entered into Farmout Agreement covering the Lake Murvaul Prospect located in Panola County, Texas with Devon Energy Production Company, L.P. In August 2011, the Company allowed the farmout to expire due to unexpected lower gas prices which made the farmout uneconomical.

During December 2010, the Company issued 200,000 shares of common stock valued at $550,000 in relation to the acquisition of remaining royalty interests in the Company's Colfax County property.

On or about December 31, 2010, the Company acquired, from another working interest owner, additional working interest in the Permian Basin for 136,957 shares of restricted common stockin two wells owned and operated by the Company. The acquisition was valued at $382,000 based on the fair market value of the shares on the day the transaction was closed. The entire transaction was allocated to proved properties.

On February 7, 2011, the Company completed the purchase of certain oil and gas leases and leasehold interests (the “Katy Acquisition”) with Katy Resources ETX, LLC, (“Katy”) a Delaware limited liability company. The assets acquired are (a) certain of Katy’s oil and gas leases and leasehold interests in Angelina, Cherokee, Houston and Panola Counties in East Texas; (b) four wellbores consisting of three producing wells each holding one of the three gas units being acquired and one shut-in well; (c) any contracts or agreements related to the foregoing lands, leases and wells; (d) any equipment located on the land or used in the operation of the foregoing land, leases or wells; and (e) any hydrocarbons produced from or attributable to the foregoing land, the leases and the wells and other related assets. The aggregate purchase price was $11.7 million, subject to purchase price adjustments. The Katy Acquisition includes total acreage held by production 1,864 gross acres (1,150 net acres). In addition, there are 6,687 gross acres (6,284 net acres) under primary terms on numerous leases. The producing wells and surrounding acreage have been unitized under Texas Railroad Commission rules. Under the terms of the agreement, the purchase price was be paid in the form of (i) $1 million in cash, (ii) $4 million in the form of a note payable, and secured by a deed of trust, and (iii) 1,583,710 shares of the Company’s restricted Common Stock.

Note 4 – Asset Retirement Obligations

The Company provides for future asset retirement obligations under the provisions of ASC Topic 410, Asset Retirement and Environmental Obligations. The present value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method. The associated liability is classified in current and long-term liabilities in the Unaudited Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the Unaudited Consolidated Statement of Operations.

A reconciliation of the Company’s asset retirement obligations for the year ended April 30, 2012 is as follows:


Beginning of period	$	58,000
Liabilities incurred		-
Liabilities settled		–
Accretion expense		70,000
Revisions to estimate		–

End of period		128,000
Less: current asset retirement obligations		125,000

Long-term asset retirement obligations	$	3,000

Note 5 – Notes Payable

The Company’s outstanding Notes Payable consisted of the following as of April 30, 2011:

Notes Payable
Balance as of April 30, 2011	$	88,000
Proceeds		400,000
Payments		(14,000	)
Balance as of April 30, 2012	$	474,000

Notes payable - related parties
Balance as of April 30, 2011	$	5,000,000
Proceeds		225,000
Conversions to common stock		(1,000,000	)
Balance as of April 30, 2012	$	4,225,000

During the year ended April 30, 2012, the Company issued a convertible debenture to an unrelated party, and one to McMillan Family Trust (please see footnote litigation) for cash received of $625,000 in cash. The Company has made cash payments in the amount of $14,000 and converted $1,000,000 of notes payable into restricted common shares pursuant to their agreements.

A summary of notes payable at April 30, 2012 is as follows:

Principal Balance (000 omitted)		Date	Interest rate		Collateral& Terms	Maturity
$	43	2/2/2011		8%	Ford Truck, interest rate of 8%, payable in 36 monthly payments of $1,481.70	2/2/2014
	38			0%	Certificates of Deposit at a financial institution	Upon completion of plugging
	400	03/07/2012		5%	Convertible general obligation debenture	03/07/2015
	7	4/20/2006		6%	General obligation	On Demand
$	488

$	4,000	2/7/2011		8%	Certain oil and gas properties in Texas, payable at maturity	8/7/2011
	225	10/14/2011		8%	General obligation	Upon settlement
$	5,000

Long-term debt matures at $15,000 in 2013, $28,000 in 2014. The Company has classified all non-current maturities as current.

Note 6 – Stockholders’ Equity (Deficit)

Common Stock

Issuances of common stock were valued at the fair market value on the date of issuance.

In March of 2012, the Company’s Board of Directors voted to exchange Officers, Directors and employees who were holding options on one share of the Company’s common stock to exchange it for one share of the Company’s common stock. The unamortized portion of the value of the options issued was expensed and the value of the shares on the date of election was recorded as a modification to the agreement. The Company recognized compensation expense of $2,935,000 in the issuance of 3,490,000 shares of common stock.

During the year ended April 30, 2012, the Company issued 657,571 shares of its common stock to certain individuals and service providers in return for their services. The Company recognized an expense of $2,277,000 based on an average issuance price of $3.46 per share.

During the year ended April 30, 2012, the Company issued 720,000 shares of its restricted common stock to holders of promissory notes as payment of principal and related accrued interest totaling $1,087,000 based on an issuance range of $1.50 to $1.55 per share.

During the year ended April 30, 2012, the Company issued 2,484,500 in conversion of preferred shares presented for conversion, pursuant to the Board of Directors resolution in the prior year.

Stock-Based Compensation

In March of 2012 the Company’s Board of Directors voted to exchange Officers, Directors and employees who were holding options on one share of the Company’s common stock to exchange it for one share of the Company’s common stock. The unamortized portion of the value of the options issued was expensed and the value of the shares on the date of election was recorded as a modification to the agreement. The Company recognized compensation expense of $2,935,000 in the issuance of 3,490,000 shares of common stock.

Warrants

During the year ended April 30, 2012, the Board of Directors authorized the extension of the Expiration date of Mr. Weathers’ warrants to April 30, 2015.

During the year ended April 30, 2012, the Company issued warrants on 350,000 shares to Mr. Fields on March 9, 2012 with an exercise price of $.69.

During the year ended April 30, 2012, the Company issued warrants on 1,435,436 shares of common stock to various investors with an exercise at a price range between $1.50 and $.20.

	Number of shares under warrant		Weighted Average Exercise Price		Weighted Average Remaining Term (in years)		Aggregate Fair Value
Outstanding at April 30, 2010		1,660,000	$	1.69	$	1.5		2,230,000
Granted
Exercised		180,000		2.13		2.15		278,000
Forfeited or expired		440,000		2.01		2.00		547,000
Outstanding at April 30, 2011		1,400,000	$	1.65		1.50	$	1,961,000

Granted		1,435,436		2.13		2.15		771,000
Exercised		-		-		-		-
Forfeited or expired		700,000		1.65				1,417,000
Outstanding at April 30, 2012		2,135,436	$	1.65		1.0	$	1,315,000

Note 7 – Employment Agreements

Management Employment Contracts

Change in Control Defined. For purposes of this note, "Change in Control" shall mean the occurrence of any of the following:

Payee accepted the Note in settlement of the amounts owed to Payee by the Company for failure of the Company to perform under his Employment Agreement. The Note is for a six month term and is due December 4, 2012. The principal amount of the Note is for Two Hundred Ninety Eight Thousand Seven Hundred Ninety One and 57/100 Dollars ($298,791.57) and it bears an interest rate of four percent (4%) per annum. The Company may prepay the Note at any time without penalty or premium, upon 10 days written notice Payee and subject to the Payee’s right to convert as provided for in the Note.

Change in Control Defined. For purposes of this note, "Change in Control" shall mean the occurrence of any of the following:

5) Messrs. Schmidt, Wafford and Pennington have each agreed to continue to perform their respected duties as officers and/or directors for the next six (6) months on an at-will basis for the following salaries:

a) Donal R. Schmidt, Jr. – $25,000 per month and if the Company is not able to pay cash he agrees to accept 125,000 shares of common stock of the Company per month in lieu thereof;

b) Thimothy S. Wafford – $25,000 per month and if the Company is not able to pay cashhe agrees to accept 125,000 shares of common stock of the Company per month in lieu thereof; and

(i)	Any unpaid Base Compensation accrued through the date of termination;
(ii)	Any unreimbursed expenses properly incurred prior to the date of termination;

(iii)	Any awards previously granted pursuant to the Stock Plan that have fully vested and, if applicable, exercisable, on the date of such termination of employment;
(iv)	Any amounts or rights to which Mr. Schmidt is entitled under any other written agreements with the Company or written Company policy or pursuant to any Company benefit or welfare plans in effect on the date of termination;
(v)	In year two, one lump-sum payment of severance pay equal to two (2) times the Base Compensation and
(vi)	Beginning in year three and any subsequent year in which this contract is in effect, one lump-sum payment of severance equal to two (2) times the annualized Base Compensation Rate (at the rate then in effect at the time of such termination) for the remainder of the Term.

(i)	Any unpaid Base Compensation accrued through the date of termination;
(ii)	Any unreimbursed expenses properly incurred prior to the date of termination;

(iii)	Any awards previously granted pursuant to the Stock Plan that have fully vested and, if applicable, exercisable, on the date of such termination of employment;
(iv)	Any amounts or rights to which Mr. Wafford is entitled under any other written agreements with the Company or written Company policy or pursuant to any Company benefit or welfare plans in effect on the date of termination;
(v)	In year two, one lump-sum payment of severance pay equal to two (2) times the Base Compensation and
(vi)	Beginning in year three and any subsequent year in which this contract is in effect, one lump-sum payment of severance equal to two (2) times the annualized Base Compensation Rate (at the rate then in effect at the time of such termination) for the remainder of the Term.

The Company entered into the Secured Convertible Promissory Note, set forth above in Item 1.01, in full satisfaction of the termination of Mr. Wafford’s Employment Agreement.

(vi)	on the sixth (6th) day following the Termination Date or the next regularly scheduled pay day of the Company following the Termination Date, respectively,
(A)		any accrued but unpaid Base Salary for services rendered through the Termination Date,

(B)	any accrued but unpaid expenses required to be reimbursed under Section 4 of the Employment Agreement, and
(C)	any vacation accrued to the Termination Date, and

(vii)

(viii)

all 300,000 shares of common stock under the Stock Option.

The Company entered into the Secured Convertible Promissory Note set forth above in Item 1.01 in full satisfaction of the termination of Mr. Pennington’s Employment Agreement.

Effective July 1, 2012, Vice President of Engineering, Thomas Schaefer terminated his Employment Agreement with the Company for good cause for the Company’s failure to pay his compensation under the Employment Agreement. The definition of Good Cause in Section 8 of the Employment Agreement, includes, but is not limited to, the Company’s failure to timely pay any compensation due to the Employee under the Employment Agreement and a reduction of the Employee’s compensation without Employee’s written consent. Mr. Schaefer provided the Company with notice of its failure to pay his Base Salary and waited past the 30 day cure period. Pursuant to Section 9(b) of the Employment Contract if the Employment Contract is terminated for Good Cause the Company is liable for the following:

(i)	on the sixth (6th) day following the Termination Date or the next regularly scheduled pay day of the Company following the Termination Date, respectively,
(A)		any accrued but unpaid Base Salary for services rendered through the Termination Date,

(B)	any accrued but unpaid expenses required to be reimbursed under Section 4 of the Employment Agreement, and
(C)	any vacation accrued to the Termination Date, and

(ii)

(iii)

if the Employee terminates his employment for Good Reason, and thereafter engages in activities that are within the scope of the restrictions described in Section 7 of the Employment Agreement, Employee shall not be entitled to the severance payment described in clause (ii) of Section 9(b

Included in accrued expenses – related parties is severance liability of $6,038,718 at April 30, 2012, which was calculated using a net present value of 10% for the remaining term.

Note 8 – Litigation

Except as set forth below, we are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

Ballard Litigation

BPC Litigation

Nova Leasing Litigation

Company entered into a release with Nova pursuant to advice from the Company’s previous general counsel. The Company believes that Nova agreed to return the stock to the Company, but it was never returned. In 2011, the Company discovered that its previous general counsel (who advised the Company in connection with the Nova transaction) was also a member of Nova Leasing, but this was not disclosed to the Company at the time of the transactions. The Company added the previous general counsel as a party to the lawsuit. In the lawsuit, the Company seeks the return of the 1,200,000 shares of stock, damages and attorneys’ fees from Nova based upon claims of rescission, unjust enrichment, fraud and breach of fiduciary duty. In the lawsuit, Nova seeks damages, and attorneys’ fees from the Company.

Coral Capital Partners, Erik Nelson, and Steve Stephens Litigation

Cicerone Litigation

Note 9 – Income taxes

The Company and its subsidiaries file a consolidated federal income tax return.

The Company's effective income tax rate of 34% for the years ended April 30, 2012 and 2011 respectively differed from the federal statutory rate due to valuation adjustments of 34% for the years ended April 30, 2012 and 2011 respectively.

The tax accruals are reflected as follows:

For the year ended April 30,	2012				2011

Income taxes (benefit)		$	(8,449,000	)		$	(2,441,000	)
Change in valuation allowance			8,449,000				2,441,000

		$	0			$	0

Deferred tax assets and liabilities are as follows as of April 30:

	2012				2011

Deferred tax assets relating to:
Net operating loss carryforward		$	18,743,000			$	10,294,000

Less valuation allowance			(18,743,000	)			(10,294,000	)

Total deferred tax asset			0				0

A valuation allowance for deferred tax assets is required when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of this deferred tax asset depends on the Company's ability to generate sufficient taxable income in the future. Management believes it is more likely than not that the net deferred tax asset will not be realized by future operating results. The valuation allowance increased by approximately$8.4 million, and $2.4 million for the years ended April 30, 2012and 2011, respectively.

At April 30, 2011, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $18.7 million, to expire in years 2018 through 2031.

The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. Only tax positions that meet the more-likely-than-not recognition threshold are recorded.

Note 11-Related party transactions

The Company utilizes air service from S&W Air for service to the CEO and other parties traveling on the Companies behalf. Those services are provided at a rate of $1,500 per hour. S&W Aircraft Leasing, LLC (“S&W Air”) is owned by our CEO and COO. S&W Air does provide similar service on a limited basis to other parties at slightly higher rates.

The Company utilized the services of OMG Ventures LLC (“OMG”) for the purposes of making investor presentations. OMG is owned by our CEO and COO.

Change in Control Defined. For purposes of this note, "Change in Control" shall mean the occurrence of any of the following:

Payee accepted the Note in settlement of the amounts owed to Payee by the Company for failure of the Company to perform under his Employment Agreement. The Note is for a six month term and is due December 4, 2012. The principal amount of the Note is for Two Hundred Ninety Eight Thousand Seven Hundred Ninety One and 57/100 Dollars ($298,791.57) and it bears an interest rate of four percent (4%) per annum. The Company may prepay the Note at any time without penalty or premium, upon 10 days written notice Payee and subject to the Payee’s right to convert as provided for in the Note.

Change in Control Defined. For purposes of this note, "Change in Control" shall mean the occurrence of any of the following:

a) Donal R. Schmidt, Jr. – $25,000 per month and if the Company is not able to pay cash he agrees to accept 125,000 shares of common stock of the Company per month in lieu thereof;

b) Thimothy S. Wafford – $25,000 per month and if the Company is not able to pay cashhe agrees to accept 125,000 shares of common stock of the Company per month in lieu thereof; and

(i)	Any unpaid Base Compensation accrued through the date of termination;
(ii)	Any unreimbursed expenses properly incurred prior to the date of termination;

(iii)	Any awards previously granted pursuant to the Stock Plan that have fully vested and, if applicable, exercisable, on the date of such termination of employment;
(iv)	Any amounts or rights to which Mr. Schmidt is entitled under any other written agreements with the Company or written Company policy or pursuant to any Company benefit or welfare plans in effect on the date of termination;
(v)	In year two, one lump-sum payment of severance pay equal to two (2) times the Base Compensation and
(vi)	Beginning in year three and any subsequent year in which this contract is in effect, one lump-sum payment of severance equal to two (2) times the annualized Base Compensation Rate (at the rate then in effect at the time of such termination) for the remainder of the Term.

(i)	Any unpaid Base Compensation accrued through the date of termination;
(ii)	Any unreimbursed expenses properly incurred prior to the date of termination;

(iii)	Any awards previously granted pursuant to the Stock Plan that have fully vested and, if applicable, exercisable, on the date of such termination of employment;
(iv)	Any amounts or rights to which Mr. Wafford is entitled under any other written agreements with the Company or written Company policy or pursuant to any Company benefit or welfare plans in effect on the date of termination;

(v)	In year two, one lump-sum payment of severance pay equal to two (2) times the Base Compensation and
(vi)	Beginning in year three and any subsequent year in which this contract is in effect, one lump-sum payment of severance equal to two (2) times the annualized Base Compensation Rate (at the rate then in effect at the time of such termination) for the remainder of the Term.

The Company entered into the Secured Convertible Promissory Note, set forth above in Item 1.01, in full satisfaction of the termination of Mr. Wafford’s Employment Agreement.

(vi)	on the sixth (6th) day following the Termination Date or the next regularly scheduled pay day of the Company following the Termination Date, respectively,
(A)		any accrued but unpaid Base Salary for services rendered through the Termination Date,

(B)	any accrued but unpaid expenses required to be reimbursed under Section 4 of the Employment Agreement, and
(C)	any vacation accrued to the Termination Date, and

(vii)

(viii)

all 300,000 shares of common stock under the Stock Option.

The Company entered into the Secured Convertible Promissory Note set forth above in full satisfaction of the termination of Mr. Pennington’s Employment Agreement.

(i)	on the sixth (6th) day following the Termination Date or the next regularly scheduled pay day of the Company following the Termination Date, respectively,
(A)	any accrued but unpaid Base Salary for services rendered through the Termination Date,

(B)	any accrued but unpaid expenses required to be reimbursed under Section 4 of the Employment Agreement, and
(C)	any vacation accrued to the Termination Date, and
(ii)	severance pay in an amount equal to Employee’s Base Salary for a period beginning on the Termination Date and ending one (1) year from the Termination Date or if the Termination Date occurs in the third (3rd) year of this Agreement then Employee shall receive his pro-rata Base Salary until the third (3rd) anniversary of the date of this Agreement. Payments shall be payable in equal monthly installments beginning on the last day of the first month following the Termination Date; provided, however, that none of the benefits payable under Section 9(b)(ii) will be payable unless, and the obligation to pay any severance pursuant to Section 9(b)(ii) shall not accrue until, the Employee has signed and delivered an executed general release, which has become irrevocable, satisfactory to the Company in its reasonable discretion, releasing the Company and its Affiliates and their respective officers, directors, managers, members, partners and employees from any and all claims or potential claims arising from or related to the Employee’s employment or termination of employment, and
(iii)	if the Employee terminates his employment for Good Reason, and thereafter engages in activities that are within the scope of the restrictions described in Section 7 of the Employment Agreement, Employee shall not be entitled to the severance payment described in clause (ii) of Section 9(b).

The Company does not utilize currently, but historically did utilize a consultant, who was a 16b reporting party.

Below is a summary of related party transactions

Note 10 – Subsequent Events

On July 11, 2012, Sun River Energy, Inc. (the "Company") entered into a Purchase Sale Agreement (“PSA”) with Katy Resources ETX, LLC (“Katy”) to sell the Company’s interest in approximately 650gross acres of leasehold interest inthe Neal Heirs Gas Unit in Panola Counties in East Texas. The sale is limited to the Company’s interest in the leases commencing at the surface of the Earth and extending down to the Topof the Travis Peak Formation, less and except the wellbore of the Neal Heirs #1 Well(the “Well”), all personal property and equipment located thereon or used and obtained in connection therewith and the right to produce oil and/or gas from same, together with the subsurface rights in and under 40 acres in the form of a square with the Well in the center.The PSA has an effective date of July 11, 2012and an anticipated closing date of no later than August 31, 2012.

Under the terms of the PSA, at closing, the Company and Katy will agree to amend the Promissory Note between the Company and Katy dated February 7, 2011(the “Note”) and reduce the principal balance on the Noteby two million dollars($2,000,000).

Before the closing, Katy intends to conduct customary due diligence of the assets to be acquired so as to assess material title deficiencies and environmental matters. If, prior to the closing, the parties ultimately determine that the aggregate dollar value of any title deficiencies, casualty or condemnation losses, or environmental liabilities exceeds $300,000 of the purchase price, then, pursuant to the Purchase Agreement, either the Company or Katy may terminate the Purchase Agreement.

Each party’s obligation to consummate the Acquisition is conditioned upon, among other things, (i) confirmation of the parties’ representations and warranties as of the closing, (ii) the parties’ performance, in all material respects, of all covenants, and (iii) the receipt of all required approvals and consents to the Acquisition. This is a summary only and not a complete list of conditions to closing.

Note 11– Oil and Gas Reserve Data (unaudited)

In December 2008, the United States Securities and Exchange Commission announced that it had approved revisions to modernize the oil and gas reserves reporting requirements. The Company adopted these rules effective April 30, 2010.

The following estimates of proved reserve quantities and related standardized measure of discounted future net cash flows are estimates only, and do not purport to reflect realizable values or fair market values of the Company's reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company's reserves are located in the United States.

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods.

The standardized measure of discounted future net cash flows for 2012 was computed by applying average oil and gas prices for the 12 months prior to year-end to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10%.

Preparation of reserves estimates. The Company maintains adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from available accounting records, which are subject to quarterly reviews. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. The Company’s current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated in the reserve database as well and verified to ensure their accuracy and completeness.

Once the reserve database has been entirely updated with current information and all relevant technical support material has been assembled, Sun River’s independent engineering firm McCartney Engineering, LLC. meets with Sun River’s technical personnel to review field performance and future development plans. Following these reviews the reserve database and supporting data is furnished to McCartney Engineering, LLC so that they can prepare their independent reserve estimates and final report.

McCartney Engineering, LLC is a Colorado Registered Engineering Firm. Our primary contact at Jack McCartney is Mr. McCartney, Manager. Mr. McCartney is a State of Colorado Licensed Professional Engineer. See Exhibit 99.2 of this Annual Report on Form 10-K for the consent from McCartney Engineering, LLC and further information regarding the professional qualifications of Mr. McCartney.

The following summaries of changes in reserves and standardized measure of discounted future net cash flows were prepared from estimates of proved reserves developed by McCartney Engineering, LLC.independent petroleum consultants.

Summary of Changes in Proved Reserves

	As of April 30, 2012
	bbls			Mcf
Proved reserves
Beginning of year		57,600			14,669,900
Purchase of reserves in place		-			-
Discoveries and extensions		-			-
Revisions of previous estimates		(57,589	)		(14,509,532	)
Production		-			(61,000	)

End of year		11			99,368

Proved developed reserves
Beginning of year		17,300			4,513,600
End of year		11			99,368
Proved undeveloped reserves
Beginning of year		40.2			10,156,300
End of year		-			-

Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
	April 30,
	2012

Future cash inflows	$	494,119
Future production costs and taxes		293,218
Future development costs		-
Future income tax expenses		-

Net future cash flows	$	200,901
Discounted at 10% for estimated timing of cash flows		(45,500	)

Standardized measure of discounted future net cash flows	$	155,401


Year Ended April 30, 2012

Estimated Proved Natural Gas and Oil Reserves:
Net natural gas reserves (Mcf):
Proved developed		99,369
Proved undeveloped		-
Total		99,369
Net oil reserves (Bbls):
Proved developed		11
Proved undeveloped		-
Total		11
Total Net Proved Natural Gas & Oil Reserves (Mcfe)		99,435
Estimated Present Value of Net Proved Reserves:
PV-10 Value (in thousands)
Proved developed	$	155
Proved undeveloped		-
Total	$	155
Less: future income taxes, discounted at 10%		—
Standardized measure of discounted future net cash flows (in thousands)(3)	$	155

Prices Used in Calculating Reserves:
Natural Gas (per Mcf)	$	4.97
Oil (per Bbl)	$	95.48
Proved Developed Reserves (MCFe)		99,435

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices at the first of the month for the twelve months prior to April 30, 2012, along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The prices used at April 30, 2012 were $95.48 per Bbl and $4.97 per Mcf. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carry-forwards, for both regular and alternative minimum tax. The Company's net operating loss carryforward and investment base is expected to fully absorb any future income taxes from oil and gas operations.

Attached files

SUN RIVER ENERGY, INC Reports

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