SUN RIVER ENERGY, INC - FORM 10-K

Attached files

file	filename
EX-23.1 - CONSENT - SUN RIVER ENERGY, INC	snrv10k0ex23143011.htm
EX-31.2 - SUN RIVER ENERGY, INC	snrv10k0ex31243011.htm
EX-32.1 - SUN RIVER ENERGY, INC	snrv10k0ex32143011.htm
EX-31.1 - SUN RIVER ENERGY, INC	snrv10k0ex31143011.htm
EX-21.1 - SUBSIDIARIES - SUN RIVER ENERGY, INC	snrv10k0ex21143011.htm
EX-32.2 - SUN RIVER ENERGY, INC	snrv10k0ex32243011.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, 2011

¨ 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.

5950 Berkshire Lane, Suite 1650, Dallas, Texas 75225

(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 ¨ 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, 2010 was $29,456,192.

Number of shares of the registrant’s common stock outstanding at June 15, 2011 was 31,084,635.

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, 2011, in connection with the registrant's 2011 Annual Meeting of Stockholders, are incorporated herein by reference into Part III of this Annual Report on Form 10-K.

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SUN RIVER ENERGY, INC.

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED APRIL 30, 2011

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

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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.

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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.

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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 used 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.

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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.

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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.

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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 three 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, the Permian Basin located in Tom Green County, Texas 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.

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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 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 the Permian Basin in West Texas. While continuing the development of our New Mexico assets, we have broadened our areas of interest geographically to include acreage positions in the Permian Basin and East Texas in order to provide the Company with both reserves and production in known basins, along with the opportunity for low risk, infill development drilling in mature fields.

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 S. 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
AAccounts payable		(45,000	)
Net assets acquired		101,000
Value of common stock		387,000
Goodwill	$	286,000

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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 included 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. This cashless farmout covers approximately 5,700 gross acres (5,470 net acres) in the prolific Carthage Field, Panola County, Texas. The farmout provides the Company with over 100 net drilling locations. The primary targets will be the Cotton Valley, Travis Peak and Pettit formations. 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. The Lake Murvaul area has been a core area for Devon and has allowed them to perfect horizontal Cotton Valley drilling techniques in over 92 wells. Horizontal Cotton Valley wells, as close as two miles from the Sun River acreage, can recover as much as 5 BCFE.

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 stock in 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. We allocated the entire purchase price to unevaluated 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) 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.

Subsequent Material Events – Company Business

As of the May 31, 2011, the Company has issued 500,000 shares for $10,000,000 with net proceeds to the Company of $9,401,600. As of April 30, 2011, the Company had issued 452,550 shares for $8,547,000 net of which 201,550 shares were subsequently converted to 2,015,500 shares of the Company’s restricted common stock. 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. From the period April 30, 2011 to May 31, 2011 the Company completed the sale of the 48,700 units of authorized 8% Series A Cumulative Convertible Preferred Stock for net proceeds of $879,600.

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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.

From the period April 30, 2011 to May 31, 2011 the Company completed the sale of the 47,450 units of authorized 8% Series A Cumulative Convertible Preferred Stock for net proceeds of $879,600. During this same period, 66,000 units of authorized 8% Series A Cumulative Convertible Preferred Stock were converted and certificates for the 660,000 shares of the Company’s restricted Common Stock issued.

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.

Management Employment Contracts

Mr. Schmidt is employed for a three-year term by the Company as President and CEO and Mr. Wafford is employed for a three-year term as the COO, both effective August 1, 2010. Additionally, pursuant to the contracts, Mr. Schmidt was appointed as a director along with Robert B. Fields.

On October 15, 2010, the Board of Directors of Sun River Energy, Inc. (the “Board”) appointed Thomas Schaefer, age 38, as the Company’s Vice President of Engineering. From September 1, 2010 to October 15, 2010, Mr. Schaefer served as the Company’s Senior Petroleum Engineer. Mr. Schaefer is responsible for all aspects of drilling, completion and operation of wells on Company-operated properties in Texas and New Mexico. Effective September 1, 2010, the Company entered into an employment agreement with Mr. Schaefer, which remains in place following his appointment as an executive officer of the Company. The employment agreement provided for an initial term of three years and will automatically renew for additional one-year terms unless either party gives notice 30 days prior to the end of the then-current term of its intent to terminate the agreement.

On January 12, 2011, the Board appointed Jay Leaver, age 48, as the Company’s Vice President of Geology. Previously he was the Company’s Senior Geologist. Mr. Leaver is responsible for all aspects of geology, completion and operation of wells on Company-operated properties in Texas and New Mexico. Mr. Leaver served as Interim-President of Sun River Energy, Inc. from September 23, 2009 to August 3, 2010 and as a consulting geologist from August 3, 2010 to December 22, 2010. Effective December 22, 2010, the Company entered into an employment agreement with Mr. Leaver, which remains in place following his appointment as an executive officer of the Company. The employment agreement provides for an initial term of three years and will automatically renew for additional one-year terms unless either party gives notice 30 days prior to the end of the then-current term of its intent to terminate the agreement.

On March 31, 2011, the Board appointed Judson F. Hoover, age 53, as the Company's Chief Financial Officer. Mr. Hoover replaced Mr. Schmidt as acting CFO, allowing Mr. Schmidt to focus on his duties as CEO of the Company. From January 12, 2011 to March 31, 2011, Mr. Hoover was employed by the Company on an interim basis to provide financial and other services to the Company. From June 2007 to June 2009, he served as Controller for Union Drilling, Inc., a publicly traded company in oil field services. From June 2009 to January 2011, Mr. Hoover also owned and operated a business consulting firm. Mr. Hoover’s contract provides for a term of three years and will automatically renew for additional one-year terms unless either party gives notice 30 days prior to the end of the then-current term of its intent to terminate the agreement.

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On March 31, 2011, the Board appointed James E. Pennington, age 52, as the Company's General Counsel and Secretary. Mr. Pennington had provided services as the Company's General Counsel since January 12, 2011. Previously, Mr. Pennington acted as outside legal counsel for the Company and handled a variety of legal matters for the Company. As General Counsel, Mr. Pennington is responsible for all legal matters for the Company, including Securities Exchange Commission of the United States related matters, Sarbanes Oxley compliance, corporate governance, and managing and overseeing work performed by outside legal counsel. Effective March 31, 2011, the Company entered into an employment agreement with Mr. Pennington, which agreement will remain in place following his appointment as an executive officer of the Company. The employment agreement provides for an initial term of three years and will automatically renew for additional one-year terms unless either party gives notice 60 days prior to the end of the then-current term of its intent to terminate the agreement.

Operations

East Texas Basin, Development Plan

Business Model – East Texas Basin

Sun River has significant 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 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 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.

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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 Savell Amoruso 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 9,241 gross acres (9,053 net acres) in the East Texas Basin. 3,402 gross acres (3,214 net acres) are held by production (“HBP”). The HBP acreage includes five (5) producing wells. We estimate there are over 300 drilling locations on this acreage. In addition, the Company has a Farmout Agreement with Devon Energy Production Company, L.P. in the Carthage Field in Panola County, Texas. This cashless farmout covers approximately 5,010 gross acres (4,935 net acres). The farmout provides the Company with over 100 net drilling locations. As of April 30, 2011, Cawley, Gillespie & Associates, Inc. Independent Petroleum Reservoir Engineers estimates Total Proved Reserves in East Texas are 24.5 BCFE utilizing a 48 month forward strip price deck.

The northern portion of our East Texas acreage is in Panola County and is comprised of producing wells and several infill drilling opportunities. The Crawford prospect consists of 10 possible drill locations. The Hinchen Unit consists of one (1) producing well, the Hinchen #2, completed in the Cotton Valley. The Travis Peak sands are behind pipe as demonstrated by open logs and RFT data. The average well for this acreage position is expected to produce 1.73 BCFE per well, with an expected range of 1.1 – 2.6 BCFE from 180 to 330 feet of net pay in the Cotton Valley. There are currently 18 PUD drill locations on the acreage due to its in-fill nature.

In addition to the Cotton Valley, the Travis Peak/Pettit could add as much as 0.5 BCFG to the production stream. The formations have an irregular distribution, but the Pettit is productive adjacent to these prospects and the Travis Peak is present in the Hinchen #2. Also, immediately below the Cotton Valley lies the Bossier/Haynesville. Sun River believes that the first well Sun River drills on the Crawford Prospect should test the Bossier/Haynesville, which could add as much as 0.5 BCFE to the EUR. Sun River engineers are experienced in the latest completion technology, and with success in all formations.

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 PUD drill locations on the acreage due to its in-fill nature.

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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 51 more Travis Peak/Pettit/Glen Rose/James Lime locations. There are also approximately 213 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) producing 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) producing well, the SGG Unit # 1, completed in the Travis Peak. The TB Cutler #1 well is completed in the Lower Travis Peak. The Upper Travis Peak section is behind pipe as demonstrated by mud logs and open-hole logs. The TB Cutler is awaiting installation of production tubing. 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.

Development Plans – East Texas Basin

Sun River expects to maintain continuous drilling activities on its acreage. The Company has AFE’d 23 wells with 48 scheduled completions in its 2011-2012 drilling budget, subject to available capital. These wells are designed to maximize cash flow to the Company while selectively increasing proved reserves and maintaining our existing acreage position. Using the methodology employed by Cawley, Gillespie & Associates, Inc. Independent Petroleum Reservoir Engineers, we expect to increase our Total Proved Reserves by 63 BCFE. Both the estimated volume of Total Proved Reserves and its associated cash flow are wholly-dependent upon commodity prices, drill and operating costs, and the success of drilling and completion activities.

Our 2011-2012 drilling budget targets both natural gas and crude production. Specifically, of the 23 wells we intend to drill, six wells will target a Pettit oil field in Panola County. The remaining 17 wells will target deep unconventional gas primarily in the Travis Peak, Cotton Valley and Bossier/Haynesville geological formations.

Sun River anticipates increasing its acreage position in East Texas by taking new leases, acquiring existing production or by entering into cashless farmouts. The Company anticipates acquiring much of this acreage at reduced or distressed prices. This belief is based upon a substantial amount of research relating to the finding and development costs associated with the large basin-centered shale plays. Over the last several years, many E&P operators moved away from traditional unconventional gas plays and leased hundreds of millions of acres in basin-centered shale plays. This leasing frenzy was based upon many operators’ speculative belief that long-term natural gas prices would rise and that the costs of developing their shale prospects would be substantially lower than that being experienced by the broader E&P industry at present. During the rush to shale, many operators paid significantly more in leasehold bonus cost for their shale positions than they did for their other unconventional leasehold positions. Given the fact that the current credit environment limits drilling by many of these E&P operators, they are attempting to preserve these expensive shale positions by divesting non-shale assets. As such, we have and continue to see opportunities to acquire premier non-shale acreage at advantageous prices.

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When we acquire leasehold with developed production it has three (3) types of proved reserves, as defined under current United States Securities and Exchange Commission rules. Reserves are categorized into Proved Developed Producing (“PDP”) reserves, Proved Developed Non-Producing (“PDNP”) reserves and Proved Undeveloped (“PUD”) reserves (collectively “Proved”). On acreage purchased with Proved reserves, the Company’s immediate focus would be to do limited recompletion work on selective formations in existing well-bores in order to maximize cash flow.

With respect to farmouts, the Company is looking to acquire acreage positions with no cash payments wherein the farmor typically receives a carried interest in the first well only. Under this scenario, the Company will generally be required to drill one well per gas unit. As it drills, the Company will generally earn 704 acres per gas unit. All subsequent drilling on the gas unit will require any farmor to participate on a Heads Up basis wherein the farmor must participate at the farmee’s costs. Most farmouts will be sufficiently large enough to drill multiple gas units. The Company believes that taking farmouts in the current E&P environment is a good way to acquire large acreage positions with no cash exposure and little drilling risk.

Further development upside exists in the area through ongoing farmout negotiations, leasing, and acquisitions with other operators. The Company believes the total land position available for development is in excess of 200,000 acres in the East Texas Basin.

Colfax County Prospect, New Mexico Development Plan

Business Model – Colfax County Prospect

Our wholly-owned asset in New Mexico is carried on our books at $100,000. 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. 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 (Glorietta) 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.

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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 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 have recently finished acquisition of approximately 30 square miles of 3D seismic. Shell is rumored to have recently leased deep rights to hundreds of thousands of acres in the Las Vegas and Raton Basins, presumably to further exploit this play concept. Shell recently announced plans for a 14,493 foot wildcat well in the northern portion of the Raton Basin just across the state line in Colorado.

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. We anticipate that this project will be capable of producing commercial paying quantities of gas from moderate depths. This assumption will be confirmed only through the ultimate drilling of a discovery well.

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 by high gamma ray values. An intriguing aspect of this area is the presence of the thick sections of the target section 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.

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Sun River has been monitoring closely Shell’s activities in the Tucumcari Basin. In May of 2011, Shell released most of the downhole geophysical logs from their four Cuervo wells, after action was brought against them in front of the New Mexico Oil Conservation Division in January 2010. These logs 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 overpressured, 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 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. Finally, there are indications of both condensate and helium in several of the wells offsetting the Maxwell Sub-basin. If present in the lower Pennsylvanian, both condensate and helium could significantly improve the economics of wells in the Maxwell Sub-basin as compared with the Cuervo.

Current Holdings – Colfax County Prospect

Sun River holds various ownership rights in fee simple to approximately 222,855 gross acres in Colfax County, New Mexico. These rights include approximately 171,000 acres of oil and gas mineral rights, 178,000 acres of coal extraction rights, 154,000 acres of subsurface rights to hard rock minerals, including gold, silver and copper, and 40,400 acres of timber rights. In addition to this fee acreage, the Company owns leases covering approximately 2,400 acres in New Mexico upon which three shut-in wells are located.

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.

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Sun River's holdings consist of the remaining rights of The Maxwell Land Grant Company, and include coal, timber, minerals, and oil and gas, along with some rights for ditches, railways, and telephone lines but no surface or water rights.

Development Plans – Colfax County Prospect

The Company has substantially completed it geological interpretation phase relating to discovery wells and anticipates drilling test wells in the late fall of 2011 or early spring of 2012 at select locations. The Company has AFE’d three wells in its 2011-2012 drilling budget, subject to available capital. These wells are designed to test the potential of the Colfax prospect.

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. In addition, the Company is acquiring additional leasehold acreage in New Mexico through a targeted leasing program. Such acreage will be subject to drilling requirements which do not exist on our current owned acreage; however, we believe it is in the Company’s best interest to attempt to control as much acreage in the basin as possible prior to drilling as commencement of a successful drilling program will draw unwanted competition that can typically be reasonably avoided through a careful leasing program. As such, the exact extent and location of such leasing activities is highly confidential.

A note of caution, the first test wells will require significant sidewall coring and other testing procedures to maximize information. As such, the cost of the initial well will be higher than subsequent development drilling activities. Also, there are presently no independent reserves estimates on any acreage in the Raton Basin.

Finally, Sun River is currently conducting a review to determine the commercial viability of its coal and mining rights. We have engaged several firms to explore this for us. We are in discussions of how best to monetize these assets. The non-petroleum mineral rights holdings include 31,739 acres within the Elizabethtown-Baldy Mining District, which has produced over 471,400 ounces of gold and is thought to have significant remaining potential.

Permian Basin, West Texas Development Plan

Business Model – Permian Basin

The Company intends to pursue selective purchases of structural plays in the Permian Basin, West Texas Project. Primarily, the focus will be on shallow oil prospects which are inexpensive to drill and are susceptible to new technologies that have only recently been developed. In the Permian Basin, there exists an opportunity to develop smaller fields which have been by-passed over the last 50 to 60 years as operators have searched for large deep oil formations such as the Ellenberger. As these operators developed these large deep oil formations, they created extensive geological and engineering data relating to the shallower geological zones, which were bypassed initially as either not economical at the time or did not fit a company’s business model. As a result, as the larger, deeper plays have ceased production over a horizon of 50 years, many field’s leases have lapsed, creating the opportunity for shallower reserves to be developed. In fact, the Company’s existing leasehold position was developed using this approach. In attempting to balance the Company’s portfolio, these shallow oil prospects will act as a hedge against downturns in the natural gas markets.

Geological Discussion – Permian Basin

Sun River's West Texas Project is located along the western flank of the Permian Basin. All prospects are structural and are based on subsurface geologic mapping. All prospects originally targeted the Permo-Penn Palo-Pinto, Harkey, Strawn Sand, and/or Strawn Lime at depths of 4500 feet to 5500 feet. The prospects are Stansberry (360 acres; shut-in), Lora (303 acres; shut-in), and Pecan Station North (440 acres; undrilled).

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Current Holdings – Permian Basin

Sun River owns 1,103 gross acres (1,063 net acres) in the Permian Basin in Tom Green County, Texas. 663 gross acres (623 net acres) are HBP by two (2) wells. This acreage includes three distinct prospects primarily relating to development of light crude production opportunities in the prolific Permian Basin. The existing leasehold interest is subject to participation agreements requiring four other third party working interest owners, who own interests in the existing two wellbores, to purchase leasehold from the Company at a set price in order to participate in any drilling activities or otherwise forfeit all rights under any future well drilled on that acreage. The Company owns all rights to all depths under these leases.

Developmental Plans – Permian Basin

The Company has AFE’d two wells on leases it owns in Tom Green County, Texas. Presently, no independent engineering reserve report exists on this acreage, although sufficient data exists to prepare one. In management’s opinion, a report is premature. It is anticipated that an independent report will be prepared during the current year.

Production

Production began during the last 60 days of our fiscal year. During that period we produced and sold 23,218 MCF of gas generating $98,000 in revenues, generated from our five producing wells. The average price per MCF was $4.22.

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 April 30, 2011 were prepared by Cawley, Gillespie & Associates, Inc., independent petroleum consultants, a Texas 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, 2011 under two scenarios; one under United States Securities and Exchange Commission pricing requirements, and one under current and future pricing expectations of the Company. We have provided a sensitivity analysis and the associated pricing that we believe is more reflective of future expectations than under United States Securities and Exchange Commission pricing.

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Years Ended April 30, 2011
					United States Securities and Exchanges Commission Pricing		Sensitivity Analysis
Estimated Proved Natural Gas and Oil Reserves:
Net natural gas reserves (MMcf):
	Proved developed					4,513.6		4,763.3
	Proved undeveloped					10,156.3		19,352.3
			Total			14,669.9		24,115.6
Net oil reserves (MBbls):
	Proved developed					17.3		17.7
	Proved undeveloped					40.2		49.9
			Total			57.5		67.6
Total Net Proved Natural Gas & Oil Reserves (Mcfe)						15,014.9		24,521.2
Estimated Present Value of Net Proved Reserves:
PV-10 value (in thousands)
	Proved developed				$	5,570.90	$	8,682.60
	Proved undeveloped					3,377.40		14,259.40
			Total		$	8,948.30	$	22,942.00
Less: future income taxes, discounted at 10%						—		—
Standardized measure of discounted future net cash flows (in thousands)					$	8,948.30	$	22,942.00

Prices Used in Calculating Reserves:
Natural gas (per Mcf)					$	4.13			A
Oil (per Bbl)					$	85.46			B
Proved Developed Reserves (Mcfe)						4,617.4		4,869.5
Year	A		B
2011	$	4.69	$	112.00
2012	$	4.99	$	114.00
2013	$	5.42	$	112.00
2014	$	5.55	$	108.00
2015-Thereafter	$	5.80	$	107.00

As of April 30, 2011, 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.

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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. The Company sold no oil but produced approximately 16 Bbl.

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.

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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.

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Employees

At April 30, 2011, we had 13 full-time employees and two part-time employees. 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.

Offices

Our principal executive offices are located at 5950 Berkshire lane, Suite 1650, Dallas Texas 75225, and our telephone number is (214) 369-7300. We lease 5,265 square feet for our office in Dallas, this lease expires in April 2016. We lease 471 square feet of office space for our Houston office under a renewable lease expiring August of 2011. We believe that suitable additional space to accommodate our anticipated growth will be available in the future on commercially reasonable terms.

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, 2011 and 2010, we had an accumulated deficit of $17.0 million and $9.7 million and total stockholders' equity of $13.3 million and a deficit of $2.7 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.

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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:

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•	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 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;

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•	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:

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•	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 2011 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.

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As of April 30, 2011, approximately 75% of our estimated net proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves 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.

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.

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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.

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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.

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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.

President Obama's 2011 Fiscal Year Budget includes proposals that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

The recent crisis in U.S. and world financial and securities markets could have a material adverse effect on our business and operations.

Our operations are affected by local, national and worldwide economic conditions. The national and global economy, which experienced a significant downturn throughout 2008 and 2009, including widespread recessionary conditions, record levels of unemployment, significant distress of financial institutions, extreme volatility in security prices, severely diminished liquidity and credit availability, began showing signs of gradual improvement in 2010. However, while some economic indicators trended positively, the overall rate of national and global recovery experienced during the course of 2010 and 2011 has been uneven and uncertainty continues to exist over the stability of the recovery. Although consumer confidence in the U.S. has improved since the economic downturn, it still remains low, while unemployment remains high and the housing market remains depressed. There can be no assurance that any of the recent economic improvements will be broad based and sustainable, or that they will enhance conditions in markets relevant to us. In the past, we have relied on the capital markets, particularly for equity securities, as well as the banking and debt markets, to meet financial commitments and liquidity needs if internally generated cash flow from operations is not adequate to fund our capital requirements. If the economic recovery does not continue, we may be unable to obtain equity or debt financing, which may require us to limit or reduce our capital expenditures. Additionally, the economic slowdown could continue to lead to lower demand for oil and natural gas by individuals and industries, which in turn could result in lower prices for the oil and natural gas we sell, thereby adversely resulting in declining production, lower revenues, and possibly losses and negative cash flow.

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.

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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, vice president of engineering, 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.

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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.

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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 June 15, 2011, we had 31,084,635 shares of common stock outstanding, 661,810 shares of common stock were issuable upon exercise of outstanding options. 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.

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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

Nova Leasing Litigation

On March 10, 2011, the Company filed a lawsuit in the 298th district court in Dallas County, Texas against Nova Leasing, LLC (“Nova”) 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. 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 unjust enrichment and breach of contract. On March 18, 2011, Nova filed suit against the Company in the U.S. District Court for the District of Colorado in connection with the Company’s refusal to register transfer the shares of stock. In that lawsuit, Nova seeks damages, and attorneys’ fees from the Company. The Company has filed a motion to dismiss the lawsuit in Colorado.

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Spencer Edwards Litigation

On March 10, 2010, the Company filed an Original Petition and Application for Temporary Injunction and Permanent Injunctive Relief in the County Court of Dallas County, Texas. The case is styled: Sun River Energy, Inc., JH Brech, and Richard L. Toupal v. Spencer Edwards, Inc. Cause No. cc-10—1676-E, in the County Court at Law # 5, Dallas County, Texas.

The suit alleges, among other things, that Spencer Edwards, Inc. has repeatedly violated Rule 144 of the U.S. Securities Act of 1933 in the selling of Common Stock on the open market. On April 27, 2011, the court granted summary judgment in favor of the Company and against Spencer Edwards on the Company’s breach of contract claim, and the court reserved ruling on a claim for negligent misrepresentation against Spencer Edwards. The Company is seeking actual damages, costs and attorney’s fees, which will be determined at trial along with other claims against Spencer Edwards.

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, 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

The Quarter Ended	HIGH		LOW

April 30, 2010	$	2.05	$	1.40
January 31, 2010		2.01		1.40
October 31, 2009		2.73		2.05
July 31, 2009		2.60		1.65

As of May 24, 2011, there were an estimated 434 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.

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As of the date of this report, the Company has issued 500,000 Series A Preferred shares for $10,000,000 with net proceeds to the Company of $9,401,600. As of April 30, 2011, the Company had issued 452,000 shares for $8,547,000 net proceeds of which 201,550 shares were subsequently converted to 2,015,500 shares of the Company’s restricted common stock. 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.

Unregistered Sales of Equity

The Company made the following unregistered sales of its securities from February 8, 2011 to May 31, 2011.

Date of Sale	Title of Securities	Number of Shares	Consideration	Class of Purchaser
3/15/2011	Common Stock	216,393	Cashless exercise of warrants	Stockholder
4/15/2011 through 05/11/2011	Common Stock	2,516,000	251,600 units of Series A Preferred stock	Various Stockholders
2/11/2011 through 05/31/2011	Preferred Stock	233,950	$4,384,600 cash	Various 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, 2011 and 2010 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.

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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, 2011 of approximately $6,492,000, including cash of approximately $1,489,000. The primary source of funds for the Company during 2011 was derived from the sale of preferred stock. We currently anticipate converting $6,898,000 in current notes and accounts payable to common stock. Operational revenues should grow in excess of $1,900,000 this coming year. We will need substantial additional capital to support our proposed future operations. We have no committed source for any funds necessary to meet the investment requirements reflected in the reserve report. Our current plans for expansion look to generate between $15 million and $20 million in this next year, and a total of $50 million in the near future. Future funding is anticipated to be primarily from equity funding. These funds will be primarily utilized for expansion. No representation is made that any funds will be available when needed.

The independent registered public accounting firm's report on the Company's financial statements as of April 30, 2010, and for each of the year then ended was deregistered and, therefore, the financial statements for the year ending April 30, 2010 as included herein have been reaudited in compliance with United States Securities and Exchange Commission regulations.

Results of Operations – Year Ended April 30, 2011 Compared To Year Ended April 30, 2010

During the year ended April 30, 2011 the Company began generating revenues. We generated $98,000 in revenues, as compared to $0 in the prior year. We anticipate continued growth in revenues in the coming year as production rises. 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, 2011, the Company incurred general and administrative expenses of $7,682,000 compared to $2,243,000 during the year ended April 30, 2010. The increase of $5,439,000 or 242% was primarily a result of direct employee expenses of $3,234,000 including $973,000 for costs associated with the fair value of stock options and warrants as compared with $0 for 2010. Travel costs, increased $593,000 as compared to $112,000 during the year ended April 30, 2010, an excess of 500%.

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There were decreased lease operating expenses, production taxes, depletion and depreciation of $745,000 for the year ended April 30, 2011 as compared to the same period ended April 30, 2010, primarily due to impairment charges in 2010 of $899,000 or 83%. These costs were offset by additional costs in lease operating expenses, and taxes due to production.

During the year ended April 30, 2011, the Company recognized a net loss of $7,328,000 compared to a net loss of $3,276,000 during the year ended April 30, 2010 an increase in the loss of $4,052,000 or 124%. Besides the changes noted in increased revenues, and general and administrative expenses, there were no impairment charges in the current year, as compared to $899,000 in 2010 (please see footnote 1 in our financial statements).

Liquidity and Capital Resources

At April 30, 2011, the Company had total current assets of $1,796,000 consisting of cash and accounts receivable, an increase of approximately $1,756,000 from 2010. The total current liabilities of $8,288,000, consists primarily of notes payable, and accounts payable to related parties totaling $7,131,000. Total current liabilities increased $5,444,000, or 191% over 2010. The Company has raised over $8 million in cash from a preferred stock offering, of which approximately $3 million was used in current operations, and approximately $4 million invested in oil and gas properties. The Company continues to raise capital to invest in oil and gas properties. During the period from April 30 through the date of this report the Company has raised an additional $880,000 from the sale of 8% Series A Cumulative Convertible Preferred Stock. The Company anticipates the majority of the amounts due to related parties, approximately $5,000,000 at April 30, 2011, will either be converted to or settled in the Company’s common stock when due. As of May 31, 2011 the Company sold the remaining authorized 8% Series A cumulative Convertible Preferred Stock raising a total of $10 million, netting over $9.4 million in cash to the Company.

The Company does not have capital sufficient to meet its 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

CORRECTION OF ERRORS

As disclosed on report 8-K filed January 10, 2011 with the SEC, the Company’s previous auditor had their registration revoked from the PCAOB. The Company concluded that its previously issued financial statements for the year ended April 30, 2010 contained errors. The errors relate to the method used to record the Company's full cost pool impairment charges in the fourth quarter of 2010.

The errors in the prior full cost pool impairment charge calculations are primarily due to an evaluation of the Company’s ability at that time to complete in an economic manner the wells in process. The Company did not complete in a substantial manner certain coalbed methane wells, and as of April 10, 2010, the Company did not have the resources to complete the wells. The investment in the wellbores should have been impaired at that time. The Company determined that it incorrectly failed to record that impairment. Additionally, there was an error in division calculating the loss per share as presented in the annual report from April 30, 2010, that has been corrected.

The following table summarizes the effect on the consolidated financial statements as of and for the year ended April 30, 2010 (in 000's):

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	As reported			Adjustment due to correction of errors			As Restated
Balance Sheet
Wells in process and advances	$	899		$	(899	)	$	-
This account was consolidated into
Oil and gas properties—net, based on full cost method of accounting	$	999		$	(899	)	$	100

Total assets	$	1,039		$	(899	)	$	140

Deficit accumulated during the development stage	$	(8,753	)	$	(899	)	$	(9,652	)

Total stockholders' deficit*	$	(1,335	)	$	(899	)	$	(2,234	)

Total liabilities and stockholders' deficit	$	1,039		$	(899	)	$	140

Statement of operations

Impairment charge	$	-		$	899		$	899

Total operational expenses*	$	2,394		$	899		$	3,293

Net loss for year	$	(2,377	)	$	(899	)	$	(3,276	)

Net loss per common share basic, and fully diluted	$	(0.09	)	$	(0.05	)	$	(0.19	)

*also reflect reclassifications

Statement of cash flows:

Recent Accounting Pronouncements

Accounting Standards Codification — On July 1, 2009, the Financial Accounting Standards Board (“FASB”) instituted a new referencing system, which codifies, but does not amend, previously existing nongovernmental GAAP. The FASB Accounting Standards Codification™ (“ASC”) is now the single authoritative source for GAAP. Although the implementation of ASC had no impact on our financial statements, certain references to authoritative GAAP literature within our footnotes have been changed to cite the appropriate content within the ASC.

FASB Accounting Standards Update (“ASU”) 2010-03 was issued on January 6, 2010, and aligns the current oil and natural gas reserve estimation and disclosure requirements of ASC 932 with those in the SEC Final Rule Modernization of Oil and Gas Reporting issued December 31, 2008. The rules only apply prospectively as a change in estimate. The most significant amendments to the reserve and disclosure requirements include the following:

•	Commodity Prices – Economic producibility of reserves and discounted cash flows will be based on an unweighted arithmetic average of the first day of the month commodity price during the 12-month period ending on the balance sheet date unless contractual arrangements designate the price to be used.

•	Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.

•	Proved Undeveloped Reserve Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered.

•	Reserve Estimation Using New Technologies – Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

•

Reserve Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We will also be required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

•	Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of our total oil and natural gas proved reserves.

•	Non-Traditional Resources – The definition of oil and natural gas producing activities will expand and focus on the marketable product rather than the method of extraction.

ASU 2010-03 is effective for entities with annual reporting periods ending on or after December 31, 2009. We adopted both the FASB and the United States Securities and Exchange Commission rules.

Management does not expect adoption of recently issued but not yet effective pronouncements to have a material impact on the Company’s financial statements.

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.

Page 41 of 47

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

The Company currently provides for stock-based compensation in three ways. (1) Stock options are granted to certain employees under the Company’s Incentive Plan. (2) The issuance of restricted 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 based on the fair value of the award and is recognized as expense on a straight line basis over the requisite service period (vesting period).

The following assumptions were used to value stock options, issued under the Company’s Incentive Stock Plan, calculated using the Black-Scholes options pricing model:

	Year ended April 30,
	2011
Dividend yield		0%
Expected volatility		75-159%
Risk-free interest rate		.75% - 1.28%
Expected life	1-3 years

	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Fair Value
Outstanding at April 30, 2010	0	$	0
Granted	3,335,000	1.99		10.0	$	5,355,000
Exercised	0	0
Forfeited or expired	0	0
Outstanding at April 30, 2011	3,335,000	$	1.99	9.75	$	5,355,000

Exercisable at April 30, 2011	700,000	$	1.72	9.7	$	960,000

Page 42 of 47

There were no options exercised during the year ended April 30, 2011.

Off Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of April 30, 2011, the off-balance sheet arrangements and transactions that we had entered into included operating lease agreements, farmout agreements and gas transportation commitments. The required bond for Sun River Operating with the Texas Railroad Commission is secured with the personal guarantees of our CEO and COO. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources currently or in the future.

Commodity Price Risk

We have entered into no commodities sales or swap agreements in past year.

Interest Rate Risk

We have entered into no interest rate risk agreements in the past year.

ITEM 7A – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not Applicable

ITEM 8 – FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The audited consolidated financial statements and the related notes are set forth at pages F-1 through F-17 attached hereto.

ITEM 9 – CHANGES IN AND DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not Applicable

ITEM 9A – CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in 13a-15(e) of the Securities Exchange Act of 1934, or the Exchange Act). Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective.

Management's Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to management and the Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on our assessment, we believe that, as of April 30, 2011, our internal control over financial reporting is effective based on those criteria.

Page 43 of 47

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. The Company did add a CFO January 12, 2011, to relieve the CEO of his responsibilities as the Principal Accounting Officer.

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, 2011) 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

Page 44 of 47

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
Exhibit No.	Exhibit Description	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.H Brech	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


10.1	Amended and Restated Consulting	8-K	000-27485	10.1	11/29/2010
	Agreement with Cicerone Corporate
	Development, LLC and incorporated herein by reference.

10.2	Promissory Note dated June 10, 2010 between Sun River Energy, Inc. and J.H. Brech, LLC. and incorporated herein by reference.	10-Q	000-27485	10.2	12/20/2010
		10-Q	000-27485	10.3	12/20/2010
10.3	Promissory Note dated November 1, 2010 between Sun
	River Energy, Inc. and Cicerone Corporate Development, LLC.
	and incorporated herein by reference.

Page 45 of 47

10.4	Employment Agreement dated as of December 22, 2010 with Jay	8-K	000-27485	10.4	1/18/2011
	Leaver and incorporated herein by reference.

10.5	Settlement Agreement and Release and Covenant Not to Sue,	8-K	000-27485	10.5	1/14/2011
	dated January 10, 2011 and incorporated herein by reference.

10.6	Purchase and sale agreement with Peccary	10-Q	000-27485	10.6	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.

Page 46 of 47

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: June 22, 2011	By:	/s/ Donal R. Schmidt, Jr.
	Donal R. Schmidt, Jr. Chief Executive Officer and President
	(Principal Executive)
Date: June 22, 2011	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: June 22, 2011	By:	/ s/Donal R. Schmidt, Jr.
	Donal Schmidt, Chief Executive Officer, President and Chairman of the Board
	(Principal Executive)

Date: June 22, 2011	By:	/s/ J F Hoover
	J. F. Hoover, Chief Financial Officer (Principal Financial and Accounting Officer)

Date: June 22, 2011	By:	/s/Robert B. Fields
	Robert B. Fields and Director

Date: June 22, 2011	By:	/s/Dr Steven R. Henson
	Dr Steven R. Henson, Director

Date: June 22, 2011	By:	/s/ Stephen W. Weathers
	Stephen W. Weathers, Director

Page 47 of 47

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

SUN RIVER ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS


	Page
Report of Independent Registered Public Accounting Firm		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

Page F-1 of F-23

Report of Independent Registered Public Accounting Firm

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

Page F-2 of F-23


Sun River Energy, Inc.	April 30,			April 30,
Consolidated Balance Sheets	2011			2010
(in thousands)				(as restated)
Assets

Current assets

Cash and cash equivalents	$	1,489		$	40

Accounts receivable, net		307			--

Total current assets		1,796			40

Oil and gas properties—net, based on full cost method of accounting:

Property subject to amortization		7,492			-

Property not evaluated and not subject to amortization		11,895			100

Furniture, fixtures, and equipment, net		145			-

Goodwill		287			-

Deposits		15			-

Total assets	$	21,630		$	140

Liabilities and stockholders' equity (deficit)

Current liabilities

Accounts payable and accrued expenses	$	1,050		$	1,640

Accrued expenses – related parties		2,131			--

Asset retirement obligations – current		19			--

Notes payable		88			629

Notes payable – related party		5,000			575

Total current liabilities		8,288			2,844

Asset retirement obligations, net of current portion		39			--
Total liabilities		8,327			2,844

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.		3			--

Common stock — $.0001 par value; authorized, 100,000,000 shares; 27,946,898 shares and 19,373,995 at April 30, 2011 and 2010, respectively.		3			2

Additional paid-in-capital		30,277			7,416

Accumulated deficit		(16,980	)		(9,652	)

Common stock to be delivered for debt		-			(470	)

Total stockholders’ equity (deficit)		13,303			(2,704	)

Total liabilities and stockholders' equity (deficit)	$	21,630		$	140

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

Page F-3 of F-23

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

	For the years ended April 30,
	2011				2010 (as restated)
Revenues		$	98			$	-


Operational expenses:
Lease operating expense			38				20
Production taxes			7				-
Impairment of oil and gas properties			-				899
Depreciation, depletion and amortization			130				1
General and administrative			7,682				2,243


Total operational expenses			7,857				3,163


Net loss from operations			(7,759	)			(3,163	)


Other income (expense)
Interest expense			(119	)			(113	)
Gain on settlement of litigation			550				-


Total other income (expense)			431				(113	)


Net loss			(7,328	)			(3,276	)

Less dividends on preferred shares			(26	)			-

Net loss applicable to common stockholders		$	(7,354	)		$	(3,276	)

Per share information

Net loss per common share
Basic and diluted		$	(0.32	)		$	(0.18	)

Weighted average number
of common stock outstanding			23,125,517				18,311,778

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

Page F-4 of F-23

SUN RIVER ENERGY, INC.

(in thousands, except for share data)

Consolidated Statements of Stockholder’s Equity (Deficit)

For the years ended April 30, 2010 and 2011

(In thousands, except for share data)

																	Common
																	Stock
																	delivered in			Total
											Additional						advance of			Stockholders’
	Common Stock				Preferred Stock						Paid-in			Accumulated			debt			equity
	# of Shares		Amount		# of Shares			Amount			Capital			Deficit			settlement			(deficit)
Balance - April 30, 2009		16,317,423	$	2		-		$	-		$	5,131		$	(6,376	)	$	-		$	(1,243	)

Issuance of stock for conversion of note payable		2,290,036		-		-			-			572			-			-			572
Issuance of stock for debt payment		287,545		-		-			-			572			-			-			572
Issuance of stock for services		324,500		-		-			-			644			-			-			644
Issuance of stock for services - officers		125,000		-		-			-			248			-			-			248
Issuance of stock for cashless warrant exercise		29,491		-		-			-			-			-			-			-
Issuance of warrants for services		-		-		-			-			249			-			-			249
Common stock delivered in advance of debt settlement		-		-		-			-			-			-			(470	)		(470	)
Net loss for period – as restated		-		-		-			-			-			(3,276	)					(3,276	)
Balance - April 30, 2010 (as restated		19,373,995		2		-			-			7,416			(9,652	)		(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

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

Page F-5 of F-23

SUN RIVER ENERGY, INC.
Consolidated Statements of Cash Flows
(in thousands)
	For the Years Ended
	April 30,
	2011			2010 (as restated)
Cash flows from operating activities:
Net loss	$	(7,328	)	$	(3,276	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		130			1
Impairment of oil and gas properties		-			899
Equity issued for services		2,315			1,157
Gain on settlement of litigation		(550	)		-
Changes in current assets and liabilities:
Increase in accounts receivable		(307	)		-
Increase in accounts payable and accrued liabilities		3,173			1,197
Increase in deposits		(15	)		-
Net cash used in operating activities		(2,582	)		(22	)

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

Cash flows from financing activities:
Preferred stock issued for cash		8,547			-
Proceeds from debt		466			-
Proceeds (payments) from advances		-			43
Payments on notes		(478	)		(20	)
Dividends paid		(26	)
Net cash provided by financing activities		8,509			23

Net increase in cash		1,449			1

Cash and cash equivalents — beginning of period		40			39

Cash and cash equivalents — end of period	$	1,489		$	40

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

Cash paid for income taxes	$	-		$	-

Page F-6 of F-23

(Continued)

Supplemental Disclosure of Non-cash Activities:
Issuance of common stock for payment of notes payable, accounts payable and accrued interest	$	1,802	$	1,144

Issuance of common stock for oil and gas properties	$	9,840	$	-

Issuance of common stock for fixed assets, and goodwill	$	387	$	-

Issuance of notes payable to related parties for oil and gas properties	$	5,000	$	-

Issuance of notes payable for settlement of accounts payable	$	778	$	354
Issuance of stock in advance of debt settlement	$	476	$	476
Financed vehicle acquisition	$	48	$

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

Page F-7 of F-23

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 oil and gas exploration and production company. The Company’s primary focus is on development of unconventional natural gas reserves across a multi-state area. 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, 2011 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		211,648		222,855		211,648
Texas		760		455		9,584		8,560		10,344		9,015
Total		760		455		232,439		220,208		233,199		220,663

(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. The total rights approximate 222,855gross acres.

On February 7, 2011 Sun River purchased approximately 8,500 gross acres in the East Texas Basin from Katy Resources ETX, LLC. This acquisition included three (3) producing wells and one (1) well awaiting completion. Sun River has placed new completions and penetration of new zones for these wells on its drilling schedule. The Company anticipates these additional completions will increase current production from these wells.

Additionally, the Company has the right to earn approximately 5,400 net acres in the East Texas Basin under a Farmout Agreement with Devon Energy Production Company LP. This acreage is located in the Carthage Field, Panola County, Texas. The first well commenced drilling on November 30, 2010 and reached total depth on December 24, 2010. The well was subsequently logged and casing run. The well started production in April of 2011. The Company anticipates drilling the next two wells under the Farmout back to back.

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

Sun River Energy has increased equity by $16 million during the fiscal year ended April 30, 2011, during which time we raised $8.5 million from the sale of preferred shares, acquired approximately $20mm of oil and gas properties, and commenced production. We have incurred losses of $7,613,000 and $3,293,000 in the years ended April 30, 2011 and 2010, respectively, and have negative working capital of $6,492,000 at April 30, 2011. The majority of our negative working capital position at April 30, 2011 in the amount of $6,940,000 was comprised of amounts due to significant stockholders, including Officers of the Company. Based on the stock price trend, we believe $2,940,000 to the debt, which is due to officers, will be converted to common stock. The remaining $4,000,000 is due a single significant stockholder (greater than 10%). The Company has multiple options available to meet this obligation when due, summarized as follows:

Page F-8 of F-23

•	The Company will evaluate the possibility of settlement of this obligation with issuance of additional shares to the creditor; or

•	Sun River has raised over $8,500,000 in a Preferred Stock offering, and the Company presently plans on raising additional equity through the sale of additional preferred or common stock and will utilize any proceeds to pay this debt if not already settled; or

•	The Company will evaluate the availability of long term financing to refinance the debt, potentially secured with a portion of our $19,387,000 holdings in oil and gas properties; or

•	The Company may sell a portion of our oil and gas properties to pay this debt.

Our 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.

Correction of Errors

The following table summarizes the effect on the consolidated financial statements as of and for the year ended April 30, 2010 (in 000's):

	As reported			Adjustment due to correction of errors			As Restated
Balance Sheet
Wells in process and advances	$	899		$	(899	)	$	-
This account was consolidated into
Oil and gas properties—net, based on full cost method of accounting	$	999		$	(899	)	$	100

Total assets	$	1,039		$	(899	)	$	140

Deficit accumulated during the development stage	$	(8,753	)	$	(899	)	$	(9,652	)

Total stockholders' deficit*	$	(1,335	)	$	(899	)	$	(2,234	)

Total liabilities and stockholders' deficit	$	1,039		$	(899	)	$	140

Statement of operations

Impairment charge	$	-		$	899		$	899

Total operational expenses*	$	2,394		$	899		$	3,293

Net loss for year	$	(2,377	)	$	(899	)	$	(3,276	)

Net loss per common share basic, and fully diluted	$	(0.09	)	$	(0.05	)	$	(0.18	)

*also reflect reclassifications

Page F-9 of F-23

Cash Flow

Net loss for year	$	(2,507	)	$	(899	)	$	(3,406	)
Impairment of oil and gas		-			899			899

Cash used in operating activities	$	(22	)	$	-		$	(22	)

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.

Page F-10 of F-23

Stock-based compensation

Compensation expense related to stock options, restricted stock awards, and recognized in operating results (general and administrative expenses) was $395,000 and $1,237,000 for the year ended April 30, 2011 and 2010 respectively. The stock options were valued using the Black-Scholes model and the restricted stock awards were valued based on the stock price at the date of grant.

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. 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 not impaired.

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. We then discount the future value based on an intrinsic interest rate that is appropriate for us. 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.

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.

Page F-11 of F-23

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.

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.

Preferred stock dividends

We are required by the terms of our Series A preferred stock to declare dividends each calendar quarter in an aggregate amount equal to one-third of our net cash from operating activities reduced by any principal amount of debt repayment in such calendar quarter to institutional lenders and other secured creditors. This right is senior to the rights of common stockholders to receive dividend payments. As of April 25, 2011, the Board of Directors approved the conversion of the outstanding 8% Series A Cumulative Convertible Preferred Stock into the Company’s common stock, pursuant to the Company’s conversion right set forth in the Certificate of Designation of 8% Series A Cumulative Convertible Preferred Stock.

Recent accounting standards

•	Commodity Prices – Economic producibility of reserves and discounted cash flows will be based on an unweighted arithmetic average of the first day of the month commodity price during the 12-month period ending on the balance sheet date unless contractual arrangements designate the price to be used.

•	Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.

•	Proved Undeveloped Reserve Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered.

•	Reserve Estimation Using New Technologies – Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

•

Page F-12 of F-23

•	Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of our total oil and natural gas proved reserves.

•	Non-Traditional Resources – The definition of oil and natural gas producing activities will expand and focus on the marketable product rather than the method of extraction.

ASU 2010-03 is effective for entities with annual reporting periods ending on or after December 31, 2009. We adopted both the FASB and the United States Securities and Exchange Commission rules.

Management does not expect adoption of recently issued but not yet effective pronouncements to have a material impact on the Company’s financial statements.

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, 2011 (,000 omitted):

Proved Properties	Acquisition Costs		Development Costs		Depletion			Asset Retirement Costs		Total
Balance at April 30, 2010	$	-	$	-	$	-		$	-	$	-
Activity-May 1, 2010 to April 30, 2011		4,551		2,944		(61	)		58		7,492
Total	$	4,551	$	2,944	$	(61	)	$	58	$	7,492

Unevaluated Properties	Acquisition Costs		Development Costs		Impairment of Properties			Asset Retirement Costs		Total
Balance at April 30, 2009	$	999	$	-		(899	)	$	-	$	100
Activity-May 1, 2009 to April 30, 2010
Total at April 30, 2010	$	999		-	$	(899	)		-	$	100
Activity-May 1, 2010 to April 30, 2011		11,795									11,795
Total at April 30, 2011	$	12,793			$	(899	)			$	11,895

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.

Page F-13 of F-23

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

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. This cashless farmout covers approximately 5,700 gross acres (5,470 net acres) in the prolific Carthage Field, Panola County, Texas. The farmout provides the Company with over 100 net drilling locations. The primary targets will be the CottonValley, TravisPeak and Pettit formations. 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. The LakeMurvaul area has been a core area for Devon and has allowed them to perfect horizontal CottonValley drilling techniques in over 92 wells. Horizontal Cotton Valley wells, as close as two miles from the Sun River acreage, can recover as much as 5 BCFE.

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.

Page F-14 of F-23

A reconciliation of the Company’s asset retirement obligations for the year ended April 30, 2011 is as follows:


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

End of period		58,000
Less: current asset retirement obligations		19,000

Long-term asset retirement obligations	$	39,000

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, 2010	$	628,000
Proceeds		348,000
Conversions to common stock		(580,000	)
Payments		(308,000	)
Balance as of April 30, 2011	$	88,000

Notes payable - related parties
Balance as of April 30, 2010	$	576,000
Proceeds		118,000
Conversions from accounts payable		629,000
Conversions to common stock		(1,153,000	)
Payments		(170,000	)
Additions due to FTP acquisition		1,000,000
Additions due to Katy acquisition		4,000,000
Balance as of April 30, 2011	$	5,000,000

During the year ended April 30, 2011, the Company issued five interest bearing promissory notes, and one interest free notefor a total of $6,291,000on consideration of an aggregate of $466,000in cash, $48,000 for the acquisition of a vehicle, $778,000 in conversions from accounts payable, and $5,000,000 for the acquisition of oil and gas properties, and equipment. The Company has made cash payments in the amount of $474,000 and converted $1,933,000 of notes payable into restricted common shares pursuant to their agreements.

A summary of notes payable at April 30, 2011 is as follows:

Page F-15 of F-23

Principal Balance (000 omitted)		Date	Interest rate		Collateral& Terms	Maturity
$	45	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
	7	4/20/2006		6%	General obligation	On Demand
$	90

$	4,000	2/7/2011		8%	Certain oil and gas properties in Texas, payable at maturity	8/7/2011
	1,000	8/3/2010		8%	Certain properties oil and gas properties in Texas, payable at maturity	8/3/2011
$	5,000

Long-term debt matures at $15,000 in 2012, $16,000 in 2013, and $57,000 in 2014. The Company has classified all non-current maturities as current.

Note 6 – Stockholders’ Equity (Deficit)

Preferred Stock

At a Special Meeting of the Shareholders of the Company on June 23, 2008, the shareholders voted to authorize the creation of 25,000,000 shares of preferred stock with a par value of $0.0001, to be issued in such classes or series and with such rights, designations, privileges and preferences as to be determined by the Company’s Board of Directors at the time of the issuance of any preferred shares. On or about December 23, 2010, the Company filed a Certificate of Designation of 8% Series A Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”), designating 1,250,000 shares of Series A Preferred Stock. As of April 30, 2011, the Company had issued 452,550 Series A Preferred Stock shares for $8,547,000 net,of which 201,550 shares were subsequently converted to 2,015,500 shares of the Company’s restricted common stock. On April 25, 2011, the Board of Directors approved the conversion of the 8% Series A Cumulative Convertible Preferred Stock into shares of the Company’s common stock pursuant to the Company’s conversion right set forth in the Certificate of Designation. There was $26,000 of preferred dividends paid on the Series A Preferred Stock by April 30, 2011. There is $118,000 in unpaid preferred dividends at April 30, 2011 related to the Series A Preferred Stock that is expected to be settled in June or July 2011with the Company’s restricted common stock, pursuant to the conversion approved by the Board of Directors.

On April 25, 2011, the Board of Directors of Sun River Energy, Inc. (the "Company") approved the conversion of 443,850 outstanding shares of its 8% Series A Cumulative Convertible Preferred Stock into 4,438,500 shares of the Company’s common stock pursuant to the Company's conversion right set forth in the Certificate of Designation of 8% Series A Cumulative Convertible Preferred Stock filed with the Colorado Secretary of State on December 23, 2010. The issuance of the shares of common stock upon conversion will be restricted stock as that term is defined in Rule 144 and will contain a restrictive legend to that effect. As of April 30, 2011, conversion of only 201,550 of the preferred shares had occurred.

The Series A Preferred Stock ranks senior to the Company’s common stock and any other class or series of stock issued hereafter that is junior to the Series A Preferred Stock, in each case as to distributions upon liquidation, dissolution or winding up or the Company and payment of dividends on shares of equity securities. The Stated Value of the Series A Preferred Stock is $20.00 per share (the “Stated Value”). The Series A Preferred Stock shall be entitled to receive dividends at an annual rate of 8% of the Stated Value, which shall be cumulative and accrue, whether or not declared, daily from the issuance date of Series A Preferred Stock, shall be due and payable on the last day of July, October, January and April of each year, and the accumulation of unpaid dividends shall bear interest at a rate of 8% per annum. Upon liquidation, dissolution or winding up of the Company, holders of Series A Preferred Stock are entitled to be paid, prior to any distribution to any holders of common stock and any other class or series of stock issued hereafter that is junior to the Series A Preferred Stock, an amount equal to the Stated Value plus the amount of unpaid dividends. Each share of Series A Preferred Stock may be convertible, at the option of the holder, into 10 shares of common stock. If after the issuance date of the Series A Preferred Stock the market price of the Company’s common stock for any 45 consecutive trading days exceeds $4.00 (subject to adjustment), the Company has the right to cause the holders of Series A Preferred Stock to convert all of the Stated Value of the shares of Series A Preferred Stock plus accumulated and unpaid dividends at the then-current conversion rate into shares of the Company’s common stock. Series A Preferred Stock has no voting rights whatsoever, except for any voting rights to which they may be entitled under the laws of the State of Colorado.

Page F-16 of F-23

Common Stock

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

Restricted stock awards for executive officers and employees vest ratably over one to three years. Fair value of our restricted shares is based on our closing stock price on the date of grant. As of April 30, 2011, total unrecognized stock-based compensation expense related to non-vested restricted shares was $4,394,000.

Effective February 1, 2011, the Company entered into an Amended and Restated Consulting Agreement (the “Cicerone Agreement”) with Cicerone Corporate Development, LLC, one of the Company’s principal shareholders (“Cicerone”). Pursuant to the Cicerone Agreement, Cicerone will continue to provide consulting services relating to the implementation of corporate strategies, achievement of market listing standards, debt and equity financings, and corporate governance and shareholder matters. The Cicerone Agreement amends and restates in its entirety the consulting agreement dated November 29, 2010 between the Company and Cicerone. The Cicerone Agreement shall remain in effect until August 1, 2013. Notice of termination may be given by either party upon 30 days’ prior written notice commencing six months after the effective date of the Cicerone Agreement.

As its consulting fee under the Cicerone Agreement, Cicerone is entitled to receive, on a monthly basis, $8,333. In addition, Cicerone will be entitled to receive a fee equal to 5% of the purchase price paid by the Company in connection with any oil and/or gas projects and acquisitions, acreage sales or leases introduced to the Company by Cicerone. Such fee shall be payable 50% in cash and 50% in common shares of the Company’s Common Stock based on the then-current bid price. Under the Agreement, the Company has also agreed to reimburse Cicerone’s pre-approved reasonable and necessary expenses incurred in connection with providing its consulting services. The Company recognized an expense of $408,000 of expenseunder this agreement for the year ended April 30, 2011, in addition to the warrant expense later disclosed below (see Warrants).

During the year ended April 30, 2011, the Company issued 505,000 shares of its restricted common stock to certain individuals and service providers in return for their services. The Company recognized an expense of $885,000 based on an average issuance price of $1.89per share.

During the year ended April 30 2011, the Company issued 110,000 shares of its restricted common stock to Mr. Jim Sullivan, a consultant, Mr. Joe Kelloff, the former COO, and Mr. Jay Leaver, the former President, for their services as officers of the Company (50,000, 30,000 and 30,000 shares, respectively). The Company recognized an expense of $193,000 based on an issuance range of $1.65 to $2.05 per share.

During the year ended April 30, 2011, the Company issued 1,354,457 shares of its restricted common stock to related party holders of promissory notes as payment of principal and related accrued interest totaling $1,427,000 based on an issuance range of $0.25 to $1.50 per share.

During the year ended April 30, 2011, the Company issued 825,273 shares of its restricted common stock to holders of promissory notes as payment of principal and related accrued interest totaling $205,000 based on an issuance range of $0.25 to $1.55 per share.

During the fourth quarter of 2011, the Company completed a transaction involving the conversion of $373,541 principal amount of a note, with accrued interest of $181,080, for 341,249 shares of the Company’s restricted common stock, provided to the creditor in the prior year. The fair value of the shares when transferred in 2010 was $470,000.

Page F-17 of F-23

Stock-Based Compensation

During the fiscal year ended April 30, 2011, the Company recognized expenses of $960,000 associated with the vested options issued in connection with its Incentive Stock Option Plan.

The following assumptions were used to value stock options, issued under the Company’s Incentive Stock Plan, calculated using the Black-Scholes options pricing model:

	Year ended April 30,
	2011
Dividend yield		0%
Expected volatility		75-159%
Risk-free interest rate		.75% - 1.28%
Expected life	1-3 years

	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Fair Value
Outstanding at April 30, 2010	0	$	0
Granted	3,335,000	1.99		10.0	$	5,355,000
Exercised	0	0
Forfeited or expired	0	0
Outstanding at April 30, 2011	3,335,000	$	1.99	9.7	$	5,355,000

Exercisable at April 30, 2011	700,000	$	1.72	9.7	$	960,000

There were no options exercised during the year ended April 30, 2011.

Warrants

The warrants issued toCicerone have a term of two years from the date of issuance, and exercises prices are based on the closing market price on the day of issuance and provide for a cashless exercise. The 2011 amended and restated consulting agreement with Cicerone does not provide for the monthly issuance of warrants. During the years ended April 30, 2011 and 2010, the warrants were exercisable for 180,000 and 240,000 shares, respectively. The exercise prices ranged from $1.45to $4.25 per share.

The total fair value of the warrants at the date of grant for the years ended April 30, 2011and 2010 were $1.45 to $4.25 and $1.54 to $2.73 per share, respectively, resulting in consulting expense of $278,00 and $394,000, respectively. The Company used the following assumptions to determine the fair value of warrant grants during the year ended April 30, 2011:

	April 30, 2011	April 30, 2010
Expected life	2 years	2 year s
Volatility	145% - 158%	130% - 159%
Risk-free interest rate	.34% - .76%	.67% - 1.14%
Dividend yield	0%	0%

The expected term of the warrants represents the period of time that the warrants granted are expected to be outstanding based on historical exercise trends. The expected volatility is based on the historical price volatility of the Company’s common stock. The risk-free interest rate represents the U.S. Treasury bill rate for the expected life of the related warrants.

The dividend yield represents our anticipated cash dividend over the expected life of the warrants. Warrants were exercised primarily on a cashless basis.

Page F-18 of F-23

	Number of shares under warrant		Weighted Average Exercise Price		Weighted Average Remaining Term (in years)		Aggregate Fair Value
Outstanding at April 30, 2009		1,460,000	$	1.62	$	2.02		1,996,000
Granted		240,000		1.89		2.00		248,000
Exercised		40,000		.62		.54		14,000
Forfeited or expired		0				0
Outstanding at April 30, 2010		1,660,000	$	1.69		1.5	$	2,230,000

Granted		180,000		2.13		2.15		278,000
Exercised		440,000		2.01		2.00		547,000
Forfeited or expired		0		0
Outstanding at April 30, 2011		1,400,000	$	1.65		1.0	$	1,961,000

Note 7 – Employment Agreements

Management Employment Contracts

Mr. Schmidt is employed for a three-year term by the Company as President and CEO and Mr. Wafford is employed for a three-year term as the COO, both effective August 1, 2010. Additionally, Mr. Schmidt was appointed as a director along with Robert B. Fields.

The contracts with Mr. Schmidt and Mr. Wafford provide for the payment of bonuses to each of them in the amount of $62,500 per incremental proven Bcfe. As of April 30, 2011, the Company has accrued $1,920,000 related to this provision.

On October 15, 2010, the Board appointed Thomas Schaefer, age 38, as the Company’s Vice President of Engineering. From September 1, 2010 to October 15, 2010, Mr. Schaefer served as the Company’s Senior Petroleum Engineer. Mr. Schaefer is responsible for all aspects of drilling, completion and operation of wells on Company-operated properties in Texas and New Mexico. Effective September 1, 2010, the Company entered into an employment agreement with Mr. Schaefer, whichremains in place following his appointment as an executive officer of the Company. The employment agreement provided for an initial term of three years and will automatically renew for additional one-year terms unless either party gives notice 30 days prior to the end of the then-current term of its intent to terminate the agreement.

On January 12, 2011, the Board appointed Jay Leaver, age 48, as the Company’s Vice President of Geology. From December 22, 2010 to January 12, 2011, Mr. Leaver served as the Company’s Senior Geologist. Mr. Leaver is responsible for all aspects of geology, completion and operation of wells on Company-operated properties in Texas and New Mexico. Mr. Leaver served as Interim-President of Sun River Energy, Inc. from September 23, 2009 to August 3, 2010 and as a consulting geologist from August 3, 2010 to December 22, 2010. Effective December 22, 2010, the Company entered into an employment agreement with Mr. Leaver, which remains in place following his appointment as an executive officer of the Company. The employment agreement provides for an initial term of three years and will automatically renew for additional one-year terms unless either party gives notice 30days prior to the end of the then-current term of its intent to terminate the agreement.

On March 31, 2011, the Board appointed Judson F. Hoover, age 53, as the Company's Chief Financial Officer. Mr. Hoover replacedMr. Schmidt as acting CFO, allowing Mr. Schmidt to focus on his duties as CEO of the Company. From January 12, 2011 to March 31, 2011, Mr. Hoover was employed by the Company on an interim basis to provide financial and other services to the Company. From June 2007 to June 2009, he served as Controller for Union Drilling, Inc., a publicly traded company in oil field services. From June 2009 to January 2011, Mr. Hoover also owned and operated a business consulting firm. Mr. Hoover’s contract provides for a term of three years and will automatically renew for additional one-year terms unless either party gives notice 30 days prior to the end of the then-current term of its intent to terminate the agreement.

On March 31, 2011, the Board of Directors of the Company appointed James E. Pennington, age 52, as the Company's General Counsel and Secretary. Mr. Pennington has been providing services as the Company's General Counsel since January 12, 2011. Prior to January 12, 2011, Mr. Pennington was acting as outside legal counsel for the Company and handled a variety of legal matters for the Company. As General Counsel, Mr. Pennington will be responsible for all legal matters for the Company, including Securities Exchange Commission of the United States related matters, Sarbanes Oxley compliance, corporate governance, and managing and overseeing work performed by outside legal counsel. Effective March 31, 2011, the Company entered into an employment agreement with Mr. Pennington, which agreement will remain in place following his appointment as an executive officer of the Company. The employment agreement provides for an initial term of three years and will automatically renew for additional one-year terms unless either party gives notice 60 days prior to the end of the then-current term of its intent to terminate the agreement.

Page F-19 of F-23

Note 8 – Litigation

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.

During the period prior to April 30, 2010, we accrued for costs associated with pending litigation in the amount of $550,000. During the year ended April 30, 2011, the litigation was settled and all costs were recorded, therefore the accrued costs were reversed as a gain on settlement of 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% and 35% for the years ended April 30, 2011 and 2010 respectively differed from the federal statutory rate due to valuation adjustments of 34% and 35% for the years ended April 30, 2011 and 2010 respectively.

The tax accruals are reflected as follows:

For the year ended April 30,	2011				2010

Income taxes (benefit)		$	(2,441,000	)		$	(1,158,000	)
Change in valuation allowance			2,441,000				1,158,000

		$	0			$	0

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

	2011				2010

Deferred tax assets relating to:
Net operating loss carryforward		$	10,294,000			$	3,331,000

Less valuation allowance			(10,294,000	)			(3,331,000	)

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$2.4 million, and $1.2 million for the years ended April 30, 2011and 2010, respectively.

At April 30, 2011, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $10.3 million, to expire in years 2018 through 2030.

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 10 – Subsequent Events

The Board of Directors approved the conversion of outstanding shares of its 8% Series A Cumulative Convertible Preferred Stock into the Company’s common stock pursuant to the Company's conversion right set forth in the Certificate of Designation of 8% Series A Cumulative Convertible Preferred Stock filed with the Colorado Secretary of State on December 23, 2010. The issuance of the shares of common stock upon conversion will be restricted stock as that term is defined in Rule 144 and will contain a restrictive legend to that effect.

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From the period April 30, 2011 to May 31, 2011 the Company completed the sale of the 48,700 units of authorized 8% Series A Cumulative Convertible Preferred Stock for net proceeds of $879,600. During this same period 66,000 units of authorized 8% Series A Cumulative Convertible Preferred Stock has been converted and certificates for the 660,000 shares of the Company’s restricted Common Stock issued.

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 2011 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 Cawley, Gillespie & Associates, Inc. (“CG&A”) 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 CG&A so that they can prepare their independent reserve estimates and final report.

CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Robert Ravnaas, Executive Vice President. Mr. Ravnaas is a State of Texas Licensed Professional Engineer. See Exhibit 99.2 of this Annual Report on Form 10-K for the consent from Cawley, Gillespie & Associates, Inc. and further information regarding the professional qualifications of Mr. Ravnaas.

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 CGA, independent petroleum consultants.

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Summary of Changes in Proved Reserves

	As of April 30, 2011
	Mbbls		Mmcf
Proved reserves
Beginning of year		-		-
Purchase of reserves in place		51.1		13,701.7
Discoveries and extensions		6.5		934.1
Revisions of previous estimates		-		-
Production		-		(34.1	)

End of year		57.6		14,669.9

Proved developed reserves
Beginning of year		-		-
End of year		17.3		4,513.6
Proved undeveloped reserves
Beginning of year		-		-
End of year		40.2		10,156.3

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,
	2011

Future cash inflows	$	68,790,400
Future production costs and taxes		19,619,000
Future development costs		20,436,200
Future income tax expenses		-

Net future cash flows	$	28,735,200
Discounted at 10% for estimated timing of cash flows		(19,786,900	)

Standardized measure of discounted future net cash flows	$	8,948,300

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Year Ended April 30, 2011
	United States Securities and Exchange Commission Pricing
Estimated Proved Natural Gas and Oil Reserves:
Net natural gas reserves (MMcf):
Proved developed		4,513.6
Proved undeveloped		10,156.3
Total		14,669.9
Net oil reserves (MBbls):
Proved developed		17.3
Proved undeveloped		40.2
Total		57.5
Total Net Proved Natural Gas & Oil Reserves (Mcfe)		15,014.9
Estimated Present Value of Net Proved Reserves:
PV-10 Value (in thousands)
Proved developed	$	5,570.90
Proved undeveloped		3,377.40
Total	$	8,948.30
Less: future income taxes, discounted at 10%		—
Standardized measure of discounted future net cash flows (in thousands)(3)	$	8,948.30

Prices Used in Calculating Reserves:
Natural Gas (per Mcf)	$	4.13
Oil (per Bbl)	$	85.46
Proved Developed Reserves (Mcfe)		4,617.4

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, 2011, 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, 2011 were $85.46 per Bbl and $4.13 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. The future cash flows estimated to be spent to develop the Company's portion of proved undeveloped properties through April 30, 2014 are $20.4 million.

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.

Page F-23 of F-23

Attached files

SUN RIVER ENERGY, INC Reports

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