Edgar Filing: ROYALE ENERGY INC

File No. 333-______

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-4

REGISTRATION STATEMENT

UNDER THE SECURITIES ACT OF 1933

ROYALE ENERGY, INC.

(Exact name of registrant as specified in its charter)

California	1311	33-0224120

(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

7676 Hazard Center Drive

Suite 1500

San Diego, California 92108

619-881-2800

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive

offices)

Donald H. Hosmer Stephen M. Hosmer Co-President and Co-Chief Executive Officer 7676 Hazard Center Drive Suite 1500 San Diego, California 92108 Telephone: (619) 881-2800 Facsimile (619) 881-2899	Copies to: Lee Polson, Esq. Strasburger & Price, LLP 600 Congress Avenue, Suite 1600 Austin, Texas 78701 Telephone: (512) 499-3600 Facsimile: (512) 536-5719

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Approximate dates of commencement of proposed sale to public: As soon as practicable after this registration statement becomes effective.

If the securities being registered on this Form are being offered in connection with the information of a holding company and there is compliance with General Instruction G, check the following box. ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

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

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

CALCULATION OF REGISTRATION FEE

Title of each class of securities to be registered (1)		Amount to be registered (2)			Proposed maximum offering price per unit			Proposed maximum aggregate offering price (3)			Amount of registration fee
Common Stock			1,451,925		$	2.64		$	3,833,080		$	150.64

(1)	Represents the maximum number of shares of Registrant’s common stock that may be issued in the Registrant’s exchange offer.

(2)

Pusuant to Rule 457(c) and Rule 457(f), and solely for the purpose of calculating the registration fee, the market value of the securities to be received by the Registrant in the exchange offer was calculated as the product of (i) 3,992,792 shares of Aspen Exploration Corporation common stock, which is the maximum number of shares that may be purchased by the Registrant pursuant to its exchange offer, and (ii) the average of the high and low sales prices of Aspen Exploration Corporation common stock as reported by the Over-the-Counter Bulletin Board on November 20, 2008 ($0.96).

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission acting pursuant to said section 8(a), may determine.

The information in this prospectus is not complete and may be changed. Royale may not sell these securities until the registration statement filed with the Securities and Exchange Commission, of which this document is a part, is declared effective. This prospectus is not an offer to sell these securities and Royale is not soliciting an offer to buy these securities in any state where an offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED NOVEMBER 25, 2008

ROYALE ENERGY, INC.

Offer to Exchange

Up to 1,451,925 Shares of Common Stock

ASPEN EXPLORATION CORPORATION

For shares of

Royale Energy, Inc., Common Stock

At an Exchange Ratio of 2.75 shares of Aspen Exploration Corporation Common Stock for

each share of Royale Energy, Inc., Common Stock

THE OFFER AND THE WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P;M. NEW YORK CITY TIME, ON ________________, (THE “EXPIRATION DATE”) UNLESS EXTENDED. SHARES TENDERED PURSUANT TO THE OFFER MAY BE WITHDRAWN AT ANY TIME PRIOR TO THE EXPIRATION DATE.

Royale Energy, Inc. (“Royale”) is offering to exchange up to 3,992,792 of common stock of Aspen Exploration Corporation (“Aspen”), at an exchange Ratio of one share of Royale common stock for each 2.75 shares of Aspen common stock, upon the terms and subject to the conditions in this prospectus and accompanying letter of transmittal. This offer is referred to in this prospectus as the “exchange offer” or the “offer.” In addition, you will receive cash instead of any fractional shares of Royale common stock to which you may be entitled.

Royale is seeking to acquire up to 3,992,792 of Aspen common stock in the offer for investment purposes. Royale’s offer is conditioned on receiving valid tenders of at least 3,720,036 of Aspen common stock. Following the consummation of the offer, Royale expects to have a majority of the outstanding shares of Aspen common stock, after giving effect to all shares of Aspen common stock issuable on the exercise of outstanding options, warrants, conversion rights and other existing obligations respecting the issuance of Aspen common stock. Royale expects to use its majority ownership position to elect new members of the board of directors at the next meeting of shareholders of Aspen. Royale does not intend to make any additional offers for shares of Aspen common stock or to effect any business combinations with Aspen, such as a merger or share exchange, after the tender offer. See Background and Reasons for the Offer, page 12.

Royale’s common stock is traded on the NASDAQ Global Market under the symbol “ROYL.” Aspen’s common stock is traded on the Over-the-Counter Bulletin Board under the symbol “ASPN”. On November 20, 2008, the last full trading day before Royale announced its intention to commence this offer, the closing price of a share of Aspen common stock was $0.92 and the closing price of a share of Royale common stock was $2.31. Based on these closing prices and the exchange ratio in the offer of one Royale share for each 2.75 Aspen Shares, the Royale offer has a value of $0.84 per share of Aspen common stock. This represents a 8.7% discount from Aspen’s closing share price on November 20, 2008.

FOR A DISCUSSION OF CERTAIN FACTORS THAT YOU SHOULD CONSIDER IN CONSIDERATION WITH THE OFFER, PLEASE CAREFULLY READ THE SECTION CAPTIONED “RISK FACTORS” BEGINNING ON PAGE 8.

Royale’s obligation to exchange shares of Royale common stock for shares of Aspen common stock is subject to specified conditions, which are more fully described in The Offer – Conditions of the Offer, page 22. Royale’s offer is conditioned on receiving tenders for at least 3,720,036 shares (51%) of the outstanding Aspen common stock, which, together with the shares already owned by Royale, would give it a majority of the outstanding shares of Aspen common stock.

Royale has not authorized any person to provide any information or to make any representation in connection with the offer other than the information contained or incorporated by reference in this prospectus.

ROYALE IS NOT ASKING YOU FOR A PROXY AND THIS OFFER DOES NOT CONSTITUTE A SOLICIATION OF PROXIES FOR ANY MEETING OF STOCKHOLDERS OF Aspen.

The date of this preliminary prospectus is November 25, 2008.

TABLE OF CONTENTS

		Page
Questions and Answers About the Exchange Offer		1

Where You Can Find More Information		3

Note on Aspen Information		4

Summary		4
The Companies		4
The Offer		5
Reasons for the Offer		5
Ownership of Royale After the Offer		5
Conditions of the Offer		5
Expiration Date of the Offer		5
Procedure for Tendering Shares		6
Withdrawal Rights		6
Cash Instead of Fractional Shares of Royale Common Stock		6
Regulatory Approvals		6
Comparison of Stockholders’ Rights		6
Risk Factors		6

Summary Selected Financial Data of Royale		6

Summary Selected Consolidated Financial Data of Aspen		7

Forward Looking Statements		8

Risk Factors		8
Risks Relating to the Offer		9
Risks Relating to Royale’s Business		10

Comparative Market Price Data		12

Background and Reasons for the Merger		12
Background of the Offer		12
Reasons for the Offer		14

The Offer		15
Extension, Termination and Amendment of the Offer		15
Exchange of Aspen Shares; Delivery of Royale Common Stock and Cash		16
Cash Instead of Fractional Shares of Royale Common Stock		16
Proration		17
Procedure for Tendering		17
Guaranteed Delivery		18
Matters Concerning Validity and Eligibility		19
Withdrawal Rights		19
Announcement of Results of the Offer		20
Ownership of Royale After the Offer		20
Taxation		20
No Dissenters’ Rights		21
Delaware Business Combination Statute		21
Effect of the Offer on the Market for Shares of Aspen Common Stock; Registration under the Exchange Act; Margin Requirements		21
Conditions of the Offer		22

Dividends and Distributions		25
Certain Legal Matters; Regulatory Approvals		26
Relationships with Aspen		26
Source and Amount of Funds		27

Unaudited Pro Forma Condensed Combined Financial Statements of Royale and Aspen		28

Royale’s Business		33
Plan of Business		34
Competition, Markets and Regulation		35

Royale’s Properties		35
Developed and Undeveloped Leasehold Acreage		36
Drilling Activities		36
Production		37
Net Proved Oil and Gas Reserves		37

Legal Proceedings		37

Market for Common Equity and Related Stockholder Matters		38
Dividends		38
Recent Sales of Unregistered Securities		38
Performance Graph		38

Royale Management’s Discussion and Analysis of Financial Condition and Results of Operations		39
Critical Accounting Policies		39
Results of Operations for the Three and Nine Month Periods Ended September 30, 2008, Compared to the Three and Nine Month Periods Ended September 30, 2007		40
Results of Operations for the Twelve Months Ended December 31, 2007, Compared to the Twelve Months Ended December 31, 2005		42
Results of Operations for the Twelve Months Ended December 31, 2006, Compared to the Twelve Months Ended December 31, 2005		44
Capital Resources and Liquidity		46
Changes in Reserve Estimates		48

Aspen’s Business		55
Summary of Aspen’s Business		55
Company Strategy		56
Employees		59

Royale’s Quantitative and Qualitative Disclosures about Market Risk		50

Royale’s Directors and Executive Officers

Royale’s Executive Compensation		51
Compensation Discussion and Analysis		52
Stock Options and Equity Compensation		52
Compensation Committee Report		52
Compensation of Directors		53

Security Ownership of Certain Beneficial Owners and Management of Royale		54

Aspen’s Business		55
Summary of Aspen’s Business		55
Oil and Gas Exploration and Development		55
Company Strategy		56

Employees		59

Aspen’s Properties		59
Drilling and Acquisition Activity		59
Drilling Activity		62
Production Information		63
Productive Wells and Acreage		63
Undeveloped Acreage		64
Gas Delivery Commitments		65
Present Activities		65
Drilling Commitments		65
Reserve Information – Oil and Gas Reserves		65
Office Facilities		67

Aspen is Not party to Any Legal Proceedings		67

Market for Aspen’s Common Equity and Related Stockholder Matters		67
Market Information		67
Dividends		67
Securities Authorized for Issuance Under Equity Compensation Plans		68
Recent Sales of Unregistered Securities		68

Aspen Management’s Discussion and Analysis of Financial Condition and Results of Operations		68
Overview		68
Critical Accounting Policies and Estimates		69
Liquidity and Capital Resources		73
Results of Operations		74
Quarterly Financial Information (Unaudited)		80

Quantitative and Qualitative Disclosures about Market Risk		80

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		81

Security Ownership of Certain Beneficial Owners and Management of Aspen		81


Directors and Executive Officers of Royale		82

Description of Royale Capital Stock		82
Common Stock		82
Preferred Stock		82

Comparison of Stockholders’ Rights		83

Legal Requirements Concerning the Offer		89

Experts		89
Accounting Matters		89
Engineering Matters		89
Legal Matters		89

Information Incorporated by Reference		89

Financial Statements		F-1

QUESTIONS AND ANSWERS ABOUT THE EXCHANGE OFFER

The following questions and answers are intended to address some commonly asked questions regarding the exchange offer. These questions and answers may not address all questions that may be important to you as a shareholder of Aspen. Please refer to the more detailed information contained elsewhere in this prospectus, the exhibits to this prospectus and the documents referred to in and delivered with this prospectus.

What is Royale’s Proposed Transaction?

Pursuant to the registration statement filed with the SEC, of which this prospectus is a part, Royale is offering to acquire up to 3,992,792 of outstanding Aspen common stock, in exchange for shares of Royale common stock. According to Aspen’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, as of that date, there were 7,259,622 shares of Aspen common stock outstanding. As of the date of this prospectus, Royale holds 353,125 shares of Aspen common stock, representing approximately 4.867% of its outstanding shares. Upon acceptance of this tender offer, Royale would own up to 4,345,917 shares of Aspen common stock, representing approximately 59.867% of the outstanding common stock.

How many shares will Royale Purchase in the Offer?

Royale will purchase between 3,720,036 and 3,992,792 shares of Aspen common stock in the offer. If more than 3,992,792 shares are tendered, all shares tendered will be purchased on a pro rata basis. However, in the event that fewer than 3,720,036 shares are offered, Royale may choose to forgo the offer.

What Will I Receive in Exchange for My Aspen Shares?

In exchange for each 2.75 shares of Aspen common stock purchased from you pursuant to the offer, you will receive one share of Royale common stock. In the event that there are fractional shares, you will receive cash instead of any fractional shares of Royale common stock to which you may otherwise be entitled. The number of shares of Royale common stock into which each share of Aspen common stock will be exchanged in the offer is sometimes referred to in this prospectus as the “exchange ratio.” Royale’s common stock is listed on the NASDAQ Global Market.

What is the per share value of the offer?

On November 20, 2008, the most recent full day of trading before Royale announced its intention to tender pursuant to this form, the closing price of each share of Aspen common stock was $0.92 and the closing price of Royale was $2.31. The exchange ratio in the offer would value Aspen at $0.84 per share. This represents a discount of 8.7% to the Aspen closing price described above.

What does the Board of Aspen think about the Offer?

Royale has contacted two of the three Aspen directors to discuss the possibility of a merger, and the additive value to the shareholder of each company. These discussions have not lead to meaningful progress, and have caused Royale to believe that the best interest of Aspen shareholders, including Royale, are not being served by acting management of Aspen.

On September 4, 2008, the Board of Directors of Aspen announced that it had “…decided to investigate strategic alternatives for Aspen, including the possibility of selling Aspen’s assets or considering another appropriate merger or acquisition transaction… ”. Following this announcement, Royale has made several attempts to discuss these alternatives, but Aspen has not responded to Royale’s overtures.

Why is Royale offering to exchange shares for Aspen?

Royale believes that there is value locked in the properties and assets of the company. As a holder of 4.867% of Aspen, Royale desires to protect the value of its holdings and those of the other independent shareholders from the potential loss of value that will likely result from the liquidation process currently being undertaken by Aspen management.

With little public oversight or input from Aspen’s shareholders, Aspen’s management has shown disregard and insensitivity to its shareholders. Having not held a shareholder’s meeting since February 25, 1994, and failing to submit to even the basic corporate governance, Aspen shareholders are susceptible to potential mismanagement.

Royale has a good history of expertise and alignment with Aspen shareholders that has provided openness, oversight and increased overall value. An exchange of Aspen shares will allow Royale to provide much needed drilling capital to develop Aspen assets, providing a higher value than that which would be achieved in Aspen’s current liquidation process.

What if another company offers to purchase the assets of Aspen?

Aspen has historically sold an average 70% to 85% interest in drilling prospects, leaving only 15-30% for Aspen shareholders. Royale’s business model gives us the ability to book an average of 50% interest in each new prospect. We believe that this model is likely to result in the highest value, although volatile current market conditions make it difficult to predict a level of success.

As a result, Royale will evaluate the offers received by Aspen pursuant to their liquidation process, and if warranted, proceed with the sale, with one key advantage; Royale will provide a significant level of oversight, ensuring that the full value of any sale will be passed along to the Aspen shareholders without losing value to golden parachutes or other inappropriate actions.

Will I be taxed on the Royale stock I receive?

The receipt of Royale common stock by a U.S. holder in exchange for its shares of Aspen common stock pursuant to the offer is expected to be a taxable transaction for U.S. federal income tax purposes. See The Offer-Taxation, page 20.

Is Royale’s financial condition relevant to my decision to tender in the offer?

Yes, Royale’s financial condition is definitely relevant to your decision to tender your shares because shares of Aspen common stock accepted in the offer will be exchanged for shares of Royale common stock. You should therefore, consider Royale’s financial condition before you decide to become one of Royale’s stockholders through the offer. This prospectus contains financial information regarding Royale and Aspen, which we encourage you to carefully review.

Will I have to pay any fee or commission to exchange shares

If you are the record owner of your shares and you tender your shares in the offer, you will not have to pay any brokerage fees, commissions or similar expenses. If you own your shares through a broker, dealer, commercial bank, trust company or other nominee and your broker dealer commercial bank, trust company or other nominee tenders your shares on your behalf, they may charge a fee for doing so. You should consult your broker, dealer, commercial bank, trust company or other nominee to determine whether any charges will apply.

When and how do I receive Royale shares for my tendered shares?

Royale will exchange up to 3,992,792 validly tendered and not properly withdrawn shares promptly after the expiration date of the offer, subject to the terms of the offer and the satisfaction or waiver of the conditions to the offer. Royale will exchange your validly tendered and not properly withdrawn shares by depositing shares of Royale common stock with the exchange agent, which will act as your agent for the purpose of receiving shares from Royale and transmitting such shares to you. In all cases, exchange of tendered shares will be made only after timely receipt by the exchange agent of certificates for such shares (or of a confirmation of a book-entry transfer of such shares) and a properly completed and duly executed letter of transmittal and any other required documents for such shares.

If I decide not to tender, how will the offer affect my shares?

The exchange of shares of Aspen common stock by Royale pursuant to the offer will reduce the number of holders of Aspen common stock and could adversely affect the liquidity, marketability and value of the shares of Aspen common stock.

Are dissenters’ rights available?

Dissenters` rights are the rights of stockholders, in certain cases, to receive “fair value” for their shares, plus accrued interest, as determined by a statutorily-prescribed process, which may include a judicial appraisal process. Dissenters` rights are not available in the offer.

What is the market value of my Aspen shares as of a recent date?

On November 20, 2008 the closing price of a share of Aspen common stock was $0.92. Royale, advises you to obtain a recent quotation for the Aspen common stock before deciding whether to tender your shares.

The cover page to this Prospectus states that the offer is subject to change and that the Registration Statement Filed with the SEC is not yet Effective. Does this mean that the Offer has not Commenced?

No. Completion of this preliminary prospectus and effectiveness of the registration statement are not necessary for the offer to commence. Our offer has commenced with the filing of the registration statement containing this prospectus. However, we cannot, accept for exchange any shares tendered in the offer or exchange any shares of Aspen common stock until the registration statement is declared effective by the SEC and the other conditions to the offer have been satisfied or to the extent legally permissible, waived.

WHERE YOU CAN FIND MORE INFORMATION

Royale and Aspen file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any reports, statements or other information that Royale and Aspen file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information regarding the public reference room. Royale’s and Aspen’s public filings also are available to the public from commercial document retrieval services and at the Internet website maintained by the SEC at http://www.sec.gov.

Royale has filed a registration statement on Form S-4 to register with the SEC the offering and sale of shares of Royale common stock to be issued in the offer. This prospectus is a part of that registration statement. As allowed by SEC rules, this prospectus does not contain all of the information that you can find in the registration statement or the exhibits to the registration statement. For further information, reference is made to the registration statement and its exhibits. Royale has filed, and may in the future file, amendments to the registration statement. In addition, on November 25, 2008, Royale filed with the SEC a Tender Offer Statement on Schedule TO under the Exchange Act, together with exhibits, to furnish certain information about the offer, and Royale has filed, and may in the future file, amendments to the Schedule TO. You may obtain copies of the Form S-4 and Schedule TO (and any amendments to those documents) by contacting Royale at its principal office, 7676 Hazard Center Drive, Suite 1500, San Diego, California 92108.

NOTE ON ASPEN INFORMATION

In respect of information relating to Aspen’s business, operations and management presented in, or omitted from, this prospectus, Royale has relied upon publicly available information, primarily information publicly filed by Aspen with the SEC. Information publicly filed by Aspen may be examined and copies may be obtained at the places and in the manner set forth in the preceding section, Where You Can Find More Information. Royale is not affiliated with Aspen, and non-public information concerning Aspen was not available to Royale for the purpose of preparing this prospectus. Aspen has not cooperated with Royale in, and has not been involved in, the preparation of this prospectus and has not verified the information contained in this prospectus relating to Aspen. Publicly available information concerning Aspen may contain errors. Royale has no knowledge that would indicate that any statements contained herein regarding Aspen’s operations, financial condition or condition in general, based upon such publicly filed reports and documents, are inaccurate, incomplete or untrue. However, Royale was not involved in the preparation of such reports and documents.

Pursuant to Rule 409 under the Securities Act and Rule 12b-21 under the Exchange Act, Royale has requested that Aspen provide Royale with the information required to furnish complete disclosure regarding the business, operations, financial condition and management of Aspen. Royale will amend or supplement this prospectus to include any and all information Royale receives from Aspen, if Royale receives the information before the offer expires and Royale considers it to be material, reliable and appropriate. As of the date of this prospectus, no such information has been received.

SUMMARY

The following is a summary of the information contained elsewhere in this prospectus. This summary may not contain all of the information that is important to you. You should carefully read this entire prospectus and the other documents to which it refers. You may obtain the information incorporated by reference into this prospectus without charge by following the instructions in the section entitled Where You Can Find More Information, above.

The Companies

Royale Energy, Inc.

7676 Hazard Center Drive, Suite 1500

San Diego, California 92108

619-661-2800

www.royl.com

Royale is an independent oil and natural gas producer. Royale's principal lines of business are the production and sale of natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale Energy. Royale Energy was incorporated in California in 1986 and began operations in 1988. Royale Energy's common stock is traded on the Nasdaq Global Market (symbol ROYL). On December 31, 2007, Royale Energy had 24 full time employees.

Royale Energy owns wells and leases located mainly in the Sacramento Basin and San Joaquin Basin in California as well as in Utah, Texas and Louisiana. Royale Energy usually sells a portion of the working interest in each lease that it acquires to third party investors and retains a portion of the prospect for its own account. Selling part of the working interest to others allows Royale Energy to reduce its drilling risk by owning a diversified inventory of properties with less of its own funds invested in each drilling prospect, than if Royale Energy owned the whole working interest and paid all drilling and development costs of each prospect itself. Royale Energy generally sells working interests in its prospects to accredited investors in exempt securities offerings.

The name, business address, principal occupation or employment, five-year employment history and citizenship of each director and executive officer of Royale and certain other information are set forth in Directors and Executive Officers of Royale, page 50. During the last five years, neither Royale nor, to Royale’s best knowledge, any of its directors and officers listed in this prospectus (1) had been convicted in a criminal proceeding (excluding traffic violations or similar misdemeanors) or (2) was a party to any judicial or administrative proceeding that resulted in a judgment, decree or final order enjoining the person from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws.

Aspen Exploration Corporation

2050 S. Oneida Street, Suite 208

Denver, Colorado 80224

303-639-9860

aecorp2@questoffice.net

Aspen is in the business of acquiring, exploring and developing oil an gas and other mineral properties. Aspen’s Annual Report on Form 10-KSB for the fiscal year ended June 30, 2008, states that Aspen’s major emphasis has been participation in the oil and gas segment, acquiring interests in producing oil or gas properties and participating in drilling operations. Its participation in the oil and gas exploration and development segment consists of two different lines of business – ownership of working interest and operating properties.

The Offer (See Page 15)

Royale is offering to exchange up to 3,992,792 shares of Aspen common stock at an exchange ratio of one share of Royale common stock for each 2.75 shares of Aspen common stock upon the terms and conditions contained in this prospectus and the accompanying letter of transmittal. In addition, you will receive cash instead o f any fractional shares of Royale common stock to which you are entitled. If more than 3,992,792 of Aspen common stock are validly tendered and not properly withdrawn, all shares tendered will be purchased on a pro rata basis. The offer is conditioned on a minimum of [Minimum] Aspen common shares being tendered.

Reasons for the Offer (See Page 13)

Aspen’s business and properties are similar to Royale’s. The companies have oil and gas properties in some of the same geographic regions in California and have worked cooperatively in the past. Royale believes it can capitalize on these similarities to maximize the assets and opportunities for both its shareholders and Aspen’s shareholders.

Ownership of Royale After the Offer (See Page 20)

Based on the exchange ratio for the offer, Royale estimates that if the maximum 3,992,792 of Aspen common stock are exchanged pursuant to the offer, former shareholders of Aspen would own, in the aggregate, approximately 14.584% of the outstanding shares of Royale common stock. If the minimum number of 3,720,036 Aspen common shares are exchanged, former shareholders of Aspen would own, in the aggregate, approximately 13.72% of the outstanding shares of Royale common stock.

Conditions of the Offer (See Page 22)

Royale’s obligation to exchange shares of Royale common stock for Aspen common stock is subject to several conditions, including the effectiveness with the SEC of a registration statement registering the Royale shares to be exchanged in the offer, listing the Royale shares to be exchanged for trading on NASDAQ and the valid tender of the minimum number of Aspen shares.

Expiration Date of the Offer (See Page 15)

The offer is scheduled to expire at 5:00 p.m., New York City time, on __________, unless extended by Royale. To the extent legally permissible, Royale reserves the right, in its sole discretion, at any time or from time to time:

to extend, for any reason, the period of time during which the offer is open;

to delay acceptance for exchange of, or exchange of, any shares of Aspen common stock pursuant to the offer in order to comply in whole or in part with applicable law;

to terminate the offer and not accept or exchange any shares of Aspen common stock not previously accepted or exchanged, upon the failure of any of the conditions of the offer to be satisfied prior to the expiration date;

to amend or terminate the offer without accepting for exchange or exchanging any shares of Aspen common stock if Aspen agrees to enter into a negotiated merger agreement with Royale; and

to waive any condition or otherwise amend the offer in any respect.

In addition, even if Royale has accepted for exchange, but not exchanged, shares in the offer, it may terminate the offer and not exchange shares of Aspen common stock that were previously tendered if completion of the offer is illegal or if a governmental authority has commenced or threatened legal action related to the offer.

Procedure for Tendering Shares (See Page 17)

The procedure for tendering shares of Aspen common stock varies depending on whether you possess physical certificates or a nominee holds your certificates for you and on whether or not you hold your securities in book-entry form. A letter of transmittal with instructions for tendering shares accompanies this prospectus.

Withdrawal Rights (See Page 19)

Cash Instead of Fractional Shares of Royale Common Stock (See Page 16)

Royale will not issue certificates representing fractional shares of Royale common stock pursuant to the offer. Instead, each tendering stockholder who would otherwise be entitled to a fractional share of Royale common stock will receive cash in an amount equal to such fraction (expressed as a decimal and rounded to the nearest 0.01 of a share) multiplied by the average of the closing prices, rounded to four decimal points, of Royale common stock for the 15 consecutive trading day period ending on the third trading day before the expiration date.

Regulatory Approvals (See Page 26)

Royale does not believe that the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, is applicable to the proposed transaction, and is not aware of any other material filings that will be required or advisable with any regulatory authorities in connection with the proposed transaction.

Comparison of Stockholders’ Rights (See Page 83)

You will receive Royale common stock if you tender your shares of Aspen common stock in the offer. There are a number of differences between the rights of a stockholder of Aspen, a Delaware corporation, and the rights of a stockholder of Royale, a California corporation.

Risk Factors (See Page 8)

Aspen shareholders should carefully consider the risk factors listed in this prospectus in evaluating whether to vote in favor of the proposal to adopt the merger agreement.

SUMMARY SELECTED FINANCIAL DATA OF ROYALE

The tables below present summary selected financial data of Royale prepared in accordance with U.S. generally accepted accounting principles, or GAAP. The following selected financial data should be read in conjunction with Royale’s financial statements and related notes, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other financial information in Royale’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007, as filed with the SEC on April 1, 2008, which is incorporated by reference into this prospectus. See Information Incorporated by Reference, page 89.

The statement of operations data set forth below for the nine months ended September 30, 2008 and 2007 and the balance sheet data as of September 30, 2008 and 2007, are derived from, and are qualified by reference to, the unaudited condensed financial statements of Royale and the related notes thereto that are incorporated by reference into this prospectus. The statement of operations data set forth below for the fiscal year ended December 31, 2007, 2006 and 2005, and the balance sheet data as of December 31, 2007 and 2006, are derived from, and qualified by reference to, the audited financial statements of Royale and the related notes thereto that are incorporated by reference into this prospectus. The statements of operations data for the fiscal years ended December 31, 2004 and 2003, and the balance sheet data as of December 31, 2005, 2004 and 2003, are derived from audited financial statements not included in, or incorporated by reference into, this prospectus.

	(In thousands, except earnings per share data) As of December 31,
	2007			2006			2005		2004		2003
Income Statement Data:
Revenues	$	16,557		$	24,896		$	25,643	$	25,944	$	23,265
Operating Income (Loss)		(3,885	)		(3,189	)		2,257		3,772		6,854
Net Income (Loss)		(2,779	)		(2,650	)		1,186		2,193		4,401
Basic Earnings Per Share		(0.35	)		(0.33	)		0.15		0.32		0.72

Balance Sheet Data:
Oil & Gas Properties, Equipment & Fixtures	$	23,390		$	20,526		$	31,221	$	26,137	$	22,904
Total Assets		32,571			33,715			43,043		42,549		35,671
Long Term Obligations		6,159			5,757			10,768		10,382		7,614
Total Stockholders’ Equity		12,385			15,548			18,318		17,189		15,269

	(In thousands, except earnings per share data) As of September 30,
	2008		2007
Income Statement Data:
Revenues	$	12,659	$	11,365
Operating Income (Loss)		2,026		(1,602	)
Net Income (Loss)		1,206		(1,138	)
Basic Earnings Per Share		0.15		(0.14	)

Balance Sheet Data:
Oil & Gas Properties, Equipment & Fixtures	$	21,756	$	22,615
Total Assets		34,779		30,885
Long Term Obligations		4,178		3,031
Total Stockholders’ Equity		17,446		14,026

SUMMARY SELECTED CONSOLIDATED FINANCIAL DATA OF ASPEN

The tables below present summary selected historical consolidated financial data of Aspen for each of the years in the five year period ended June 30, 2008, and for the three months ended September 30, 2008 and 2007. This information is derived from, and should be read in conjunction with, Aspen’s audited consolidated financial statements for each of the years in the five year period ended June 30, 2008, which are included elsewhere in this prospectus or in Aspen’s publicly available reports filed with the SEC. For additional information, see Aspen Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 50.

	(In thousands, except earnings per share data) As of June 30,
	2008		2007		2006		2005		2004
Income Statement Data:
Revenues	$	5,390	$	4,418	$	5,979	$	4,127	$	1,824
Operating Income (Loss)		854		712		2,988		1,639		366
Net Income (Loss)		803		925		2,970		1,487		201
Basic Earnings Per Share		0.11		0.13		0.44		0.23		0.03

Balance Sheet Data:
Oil & Gas Properties, Equipment & Fixtures	$	13,311	$	11,855	$	8,224	$	5,164	$	5,011
Total Assets		20,001		21,139		19,191		9,256		6,946
Long Term Obligations		4,764		4,825		3,017		1,098		343
Total Stockholders’ Equity		11,702		11,006		10,101		6,676		4,535

	(In thousands, except earnings per share data) As of September 30,
	2008		2007
Income Statement Data:
Revenues	$	1,293	$	1,221
Operating Income (Loss)		150		129
Net Income (Loss)		115		150
Basic Earnings Per Share		0.02		0.02

Balance Sheet Data:
Oil & Gas Properties, Equipment & Fixtures	$	12,832	$	12,870
Total Assets		18,555		22,038
Long Term Obligations		4,546		5,190
Total Stockholders’ Equity		11,553		22,038

FORWARD LOOKING STATEMENTS

This prospectus contains “forward-looking statements.” Specific forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts and include, without limitation, words such as “may,” “will,” “expects,” “believes,” “anticipates,” “projects,” “targets,” “forecasts,” “seeks,” “could” or the negative of such terms or other variations on such terms or comparable terminology. Similarly, statements that describe our objectives, plans or goals are forward-looking. Royale’s forward-looking statements are based on management’s current intent, belief, expectations, estimates and projections regarding us and our industry. These statements are not guarantees of future performance and involve risks, uncertainties, assumptions and other factors that are difficult to predict, including those discussed below. Therefore, actual results may vary materially from what is expressed in or indicated by the forward-looking statements. Readers of this prospectus are cautioned not to place undue reliance on forward-looking statements since, while Royale believes the assumptions on which the forward-looking statements are based are reasonable, we cannot be certain that these forward-looking statements will prove to be accurate. This cautionary statement is applicable to all forward-looking statements contained in this prospectus and the material accompanying this prospectus.

RISK FACTORS

You should carefully consider the following risks before deciding whether to accept the exchange offer and tender your Aspen common stock. In addition, you should read and consider the risks associated with the business of Royale, which risks can be found in the documents incorporated by reference into this prospectus, because these risks will also affect the combined company.

Risks Relating to the Offer

The exchange ratio for the offer is fixed and will not be adjusted. Because the market price of shares of Royale common stock may fluctuate, Aspen stockholders cannot be sure of the market value of the shares of Royale common stock that they will receive in the offer.

Subject to the terms and conditions of the offer, one share of Royale common stock will be exchanged for each 2.75 shares of Aspen common stock that are accepted for exchange pursuant to the offer. This exchange ratio is fixed and will not be adjusted in case of any increases or decreases in the price of Royale common stock or Aspen common stock. If the price of Royale common stock declines (which may occur as a result of a number of reasons (many of which are out of Royale’s control), including as a result of the risks described in this “Risk Factors” section), Aspen stockholders will receive less value for their shares in the offer than the value calculated pursuant to the exchange ratio on the last full trading day before Royale announced its intention to commence the original offer. Because the offer may not be completed until specified conditions have been satisfied or waived, a significant period of time may pass between the commencement of the offer and the time that Royale accepts shares of Aspen common stock for exchange. See The Offer — Conditions of the Offer, page 22. Therefore, at the time you tender your shares pursuant to the offer, you will not know the exact market value of the shares of Royale common stock that will be issued to you if Royale accepts your shares for exchange. Aspen stockholders are urged to obtain current market quotations for Royale and Aspen common stock when they consider whether to tender their shares of Aspen common stock pursuant to the offer.

Royale did not obtain an independent appraisal of the value of Aspen, or an independent opinion on the fairness of Royale’s offer.

The exchange offer was formulated by the management of Royale without obtaining any appraisal or other opinion, from an independent third party such as an investment bank about the relative values of Royale and Aspen or about the fairness of Royale’s offer. Aspen shareholders have no independent opinion or other assurance that the offer being made by Royale reflects the fair market value of the Aspen common stock to be acquired.

This transaction may adversely affect the liquidity and value of non-tendered Aspen common stock.

In the event that Royale accepts for exchange those shares tendered into the offer, the number of stockholders and the number of shares of Aspen common stock held by individual holders will be reduced. As a result, the closing of the offer could adversely affect the liquidity and market value of the shares of Aspen common stock.

Royale has only conducted a review of Aspen’s publicly available information and has not had access to Aspen’s non-public information. Any unknown liabilities of Aspen that cause a decrease in Aspen’s share price in the future may have an adverse effect on Royale’s profitability and results of operations.

To date, Royale has only conducted a due diligence review of Aspen’s publicly available information. Aspen may be subject to liabilities that Royale might have discovered if Royale had been permitted to conduct a complete due diligence review of Aspen’s non-public information. Any such currently unknown liabilities that come to light after the consummation of the offer may cause a decrease in Aspen’s share price. Such a decline in Aspen’s share price could, as a result of Royale’s ownership of Aspen shares, have an adverse effect on Royale’s profitability and results of operations.

Royale’s verification of the reliability of the Aspen information included in, or omitted from, this prospectus pursuant to Royale’s due diligence review of Aspen has been limited by Aspen’s refusal to provide Royale with the accounting and other records necessary for Royale to fully assess the financial and operating condition of Aspen. See Background of the Offer, page 12.

In respect of all information relating to Aspen presented in, or omitted from, this prospectus, Royale has relied upon publicly available information, including information publicly filed by Aspen with the SEC. Although Royale has no knowledge that would indicate that any statements contained herein regarding Aspen’s condition, including its financial or operating condition, based upon such publicly filed reports and documents, are inaccurate, incomplete or untrue, Royale was not involved in the preparation of such reports and documents.

Aspen has declined to furnish to Royale the consent of Aspen’s independent public accounting firm, which is necessary for the filing in the registration statement on Form S-4, of which this prospectus is a part, of that firm’s audit report with respect to the financial statements of Aspen for its fiscal years ended July 31, 2007 and 2006.

Royale has requested that Aspen assist Royale to obtain the consent of Aspen's independent public accounting Firm to include that Firm's report on Aspen's financial statements in this prospectus. No response has been received from Aspen. If the accounting firm's consent cannot be obtained without undue hardship, Royale submit to the SEC a request for a waiver of the requirement to include the consent of Aspen’s independent public accounting firm in the registration statement. The absence of this consent may limit recovery by investors on certain claims, and limit the ability of investors to assert claims against Aspen’s independent public accounting firm, under Section 11 of the Securities Act, for any untrue statements of a material fact contained, or any omissions to state a material fact required to be stated, in Aspen’s audited financial statements included in the registration statement. The sections of the prospectus containing Aspen financial information or information derived therefrom may, nonetheless, remain expertised under Section 11(b)(3)(c) of the Securities Act so as to provide a “due diligence” defense to third parties involved in the offer based on any claims asserted in connection with the offering of Royale common stock as part of the offer.

The market price of Royale common stock may decline as a result of the offer, and Royale’s common stock could be delisted from the NASDAQ Global Market .

The market price of Royale’s common stock may decline as a result of the offer. In particular, Royale will issue 3,992,792 shares of Royale common stock if the maximum number of shares of Aspen common stock are exchanged in offer. The increase in the number of shares of Royale common stock issued may lead to sales of such shares or the perception that such sales may occur, either of which may adversely affect the market for, and the market price of, Royale common stock.

Upon your receipt of shares of Royale common stock in the offer, you will become a stockholder in Royale, a California corporation, which may change some of the rights and privileges you hold as a stockholder of Aspen, a Delaware corporation.

Royale is a California corporation and is governed by the laws of the State of California and by its articles of incorporation and bylaws. The California Corporation Code (the “California Code”) extends to stockholders rights and privileges that may not exist under Delaware law and, conversely, does not extend other rights and privileges that you may have as a stockholder of a company governed by Delaware law. The directors of a Delaware corporation may elect to adopt provisions that have the effect of discouraging a third party from acquiring control of the corporation. These provisions could limit the price that some investors might be willing to pay in the future for shares of Royale common stock. These Delaware provisions may also have the effect of discouraging or preventing transactions involving an actual or a threatened change in control of Royale, including unsolicited takeover attempts, even though such a transaction may offer Royale stockholders the opportunity to sell their shares of Royale common stock at a price above the prevailing market price. See Comparison of Stockholders’ Rights, page 83.

Risk Factors Relating to Royale’s Business

The Hosmer Family Exerts Significant Influence Over Royale Stockholder Matters.

The control positions held by members of the Hosmer family may discourage others from making bids to buy Royale or change its management without their consent. Donald H. Hosmer and Stephen M. Hosmer are each co-president and co-chief executive officer of the company. Stephen M. Hosmer is also the chief financial officer. Harry E. Hosmer is the chairman of the board. Together, they make up three of the eight members of our board of directors. At October 15, 2008, these individuals owned or controlled the following amounts of Royale common stock, including shares they had the right to acquire on the exercise of outstanding stock options:

Name	Number of Shares		Percent*
Donald H. Hosmer		937,159		11.0	%
Stephen M. Hosmer		1,163,427		13.6	%
Harry E. Hosmer		745,697		8.7	%
Total		2,846,283		33.3	%

* Based on total of 8,505,630 outstanding shares on September 30, 2008, plus 105,000 shares the above individuals have the right to acquire on the exercise of outstanding stock options.

The amounts of stock owned by Hosmer family members make it quite likely that they could control the outcome of any contested vote of the stockholders on matters related to management of the corporation.

The Oil and Gas Industry is Highly Competitive.

The oil and gas industry is highly competitive in all its phases. Competition is particularly intense with respect to the acquisition of desirable producing properties, the acquisition of oil and gas prospects suitable for enhanced production efforts, and the hiring of experienced personnel. Our competitors in oil and gas acquisition, development, and production include the major oil companies in addition to numerous independent oil and gas companies, individual proprietors and drilling programs.

Many of our competitors possess and employ financial and personnel resources far greater than those which are available to us. They may be able to pay more for desirable producing properties and prospects and to define, evaluate, bid for, and purchase a greater number of producing properties and prospects than we can. We must compete against these larger companies for suitable producing properties and prospects, to generate future oil and gas reserves.

Governmental Regulations Can Hinder Production.

Domestic oil and gas exploration, production and sales are extensively regulated at both the federal and state levels. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, have legal authority to issue, and have issued, rules and regulations affecting the oil and gas industry which often are difficult and costly to comply with and which carry substantial penalties for noncompliance. State statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Most states where we operate also have statutes and regulations governing conservation matters, including the unitization or pooling of properties. Our operations are also subject to numerous laws and regulations governing plugging and abandonment, discharging materials into the environment or otherwise relating to environmental protection. The heavy regulatory burden on the oil and gas industry increases its costs of doing business and consequently affects its profitability. Changes in the laws, rules or regulations, or the interpretation thereof, could have a materially adverse effect on our financial condition or results of operation.

Minority or Royalty Interest Purchases Do Not Allow Us to Control Production Completely.

We sometimes acquire less than the controlling working interest in oil and gas properties. In such cases, it is likely that these properties would not be operated by us. When we do not have controlling interest, the operator or the other co-owners might take actions we do not agree with and possibly increase costs or reduce production income in ways we do not agree with.

Environmental Regulations Can Hinder Production.

Oil and gas activities can result in liability under federal, state and local environmental regulations for activities involving, among other things, water pollution and hazardous waste transport, storage, and disposal. Such liability can attach not only to the operator of record of the well, but also to other parties that may be deemed to be current or prior operators or owners of the wells or the equipment involved. We have inspections performed on our properties to assure environmental law compliance, but inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.

COMPARATIVE MARKET PRICE DATA

Royale’s common stock is traded on the NASDAQ Global Market under the symbol “ROYL.” Aspen’s common stock is quoted on the OTC Bulletin Board under the symbol “ASPN.OB.” The following table lists the closing prices per share for the common stock of Royale and Aspen on NASDAQ and the OTC Bulletin Board, respectively, on November 20, 2008, the last full trading day before Royale announced its intention to commence the tender offer. The table illustrates the number of shares and the per share value of Royale common stock you would receive based on these closing prices and the exchange ratio for the offer.

Per Share Price

of Royale

Common Stock

Per Share Price

of Aspen

Common Stock

Shares of

Royale

Common

Stock to be

Received

Per Share Value

of Royale

Common Stock

to be Received

November 20, 2008

2.31

0.92

0.364

0.84

The value of the offer will change as the market prices of Royale common stock and Aspen common stock fluctuate during the offer period and thereafter, and may therefore be different from the prices set forth above at the expiration of the offer period and at the time you receive your shares of Royale common stock. You are encouraged to obtain current market quotations prior to making any decision with respect to the offer.

BACKGROUND AND REASONS FOR THE OFFER

Background of the Offer

Royale has worked to explore and produce natural gas in much of the Sacramento Basin for more than 15 years. During this time, Royale has worked alongside Aspen Exploration in the Denverton Creek and Grimes fields, and in some instances joined together in pipeline agreements to jointly transport gas.

In early 2008, following the debilitating stroke of Bob Cohan, Aspen’s executive operations officer, the level of Aspen’s exploration activity slowed, leaving Aspen with a declining production and overall reserves. With Royale’s knowledge of Aspen’s capitalization requirements and the understanding of our similar business model which involves the sale of a portion of each drilling prospect, Royale decided to contact Aspen’s Chairman and interim CEO, R.V. Bailey, to discuss the possibility of a merger between Aspen and Royale.

In Late May 2008, Stephen Hosmer, Royale’s Chief Financial Officer contacted Mr. Bailey to suggest a discussion about such a merger. At that time Mr. Bailey expressed his desire for Mr. Cohan’s, full recovery. Mr. Bailey also stated that he would familiarize himself further about Royale for the purpose of discussing Royale’s merger overture.

On July 28, 2008, Mr. Hosmer contacted Mr. Bailey to ascertain his interest in a merger and inform him that Royale had begun purchasing Aspen’s common stock. Mr. Bailey then expressed his desire to cash out Aspen’s assets in liquidation rather than have further discussion with Royale. Mr. Hosmer suggested that they meet at the headquarters of Royale, to afford Mr. Bailey an opportunity to meet key personnel of Royale that might be involved in future development of Aspen assets should a merger be achieved. Mr. Bailey refused.

On September 4, 2008, Aspen announced that it would open a data room and begin “investiga[ting] strategic alternatives … including the possibility of selling Aspen’s assets or considering another appropriate merger or acquisition transaction.”

On September 10, 2008 Aspen announced that it had notified Mr. Cohan that his employment contract [would] not be renewed.

The same day, Mr. Hosmer received a call from Brian Wolf, Aspen’s selling agent, who is also a non-operated working interest owner and co-seller., Mr. Wolf inquired as to Royale’s desire to participate as a buyer in Aspen’s liquidation process. Mr. Hosmer expressed a desire to engage in a merger transaction because of Royale’s belief that a merger or other business combination would provide higher value to Aspen shareholders. Mr. Hosmer also declined to participate in a review of the data concerning Aspen’s assets due to Royale’s ongoing market purchases of Aspen shares. Mr. Wolf stated that Aspen would allow Royale to review Aspen’s data at a time more convenient, should Royale decide to participate. Later the same day Mr. Wolf sent, by email, a copy of a Confidentiality Agreement that would permit Royale to review Aspen’s data. Mr. Wolf then inquired as to Royale’s financial capacity to make any offer to purchase Aspen’s assets. Mr. Hosmer suggested that, as a public company, current financial information is available in the public domain, whereupon Mr. Wolf agreed that there would be no further need for Royale to make additional financial representations.

On October 21, 2008 Mr. Hosmer received a call from an unrelated third party making a claim that he had spoken to an agent for Aspen, in which the agent had expressed Aspen’s desire to exclude Royale from any review of Aspen’s data, and that any offer made by Royale should be excluded from the liquidation. Thereupon, Royale executed and returned the agreement Confidentiality Agreement received from Aspen.

The following day Mr. Wolf rejected the Confidentiality Agreement from Royale and sent a new Confidentiality Agreement with additional and more onerous restriction which sought to bar Royale from exploration activities on lands not even owned by Aspen. Such onerous restrictions would have extended to exploration of any property within one mile of Aspen lands. This restriction would have prevented Royale from operations on its own land holdings.

Mr. Hosmer placed a call to Mr. Wolf to discuss possible alternatives to the new preconditions. Mr. Hosmer suggested that such preconditions would prevent many other buyers from participating in Aspen’s liquidation sale, and asked if other potential buyers were subjected to the same. Mr. Wolf agreed to modify the preconditions only as they related to Royale’s existing property. Mr. Wolf then reasserted the precondition that Royale post a Letter of Credit (LOC) in excess of $40 Million dollars to demonstrate financial capacity. Mr. Hosmer asked that this and any other preconditions which might obstruct Royale from a review of Aspen’s data, be made in writing.

On October 22, 2008 Mr. Wolf transmitted an email stating the requirement that Royale post a LOC for an undisclosed amount “above the PV10% of 8/8ths of Aspens operated and non-operated properties”; a number which may only be determined using non-public data. This requirement would also encompass interests not reasonably expected to be included in any contemplated transaction, such as the operator’s interest in the Poplar field.

On November 4, 2008 Mr. Harry Hosmer, Chairman of the Board, placed a call to Mr. Bailey suggesting that he and Mr. Stephen Hosmer should meet in person at a location of Mr. Bailey’s choosing. Mr. Bailey said that his schedule would not permit such a meeting, and that a telephone call should be sufficient to conduct any discussions. Mr. Bailey asked that Mr. Hosmer call after he reached his winter home in Florida after November 12^th.

On November 11, 2008 Mr. Len Kemp, a member of the board of directors of Royale, traveled to Bakersfield CA and met with Bob Cohan, a personal friend, and no substantive discussion took place.

On November 17, 2008 Mr. Harry Hosmer placed a call to Mr. Bailey and left a message.

On November 20, 2008 Messrs. Harry Hosmer and Stephen Hosmer placed a call to Mr. Bailey to inform him that Royale was prepared to make this exchange offer. On the same day, Royale sent a letter to Mr. Cohan for the same purpose. After the close of business on November 20, 2008, Royale published a press release announcing their intent to make this exchange offer.

Reasons for the Offer

Over the previous 10 years Royale Energy has developed a collegial working relationship with Aspen Exploration. Both companies share a similar business model of developing natural gas reserves and production using 3D seismic imaging to find potential drilling locations, then selling a portion of those prospects to individuals. Further, both companies have developed their natural gas projects in close proximity in the Sacramento Basin of northern California.

During this time, it has been in both companies’ best interest to cooperate, exchange information, and jointly transport gas, and advance industry awareness and responsibility in the region. Aspen’s CEO, Bob Cohan, and Royale’s Stephen Hosmer have worked cooperatively on these issues of common interest.

In the process both Royale and Aspen have accumulated a large volume of three dimensional seismic (3D) data which is used to define and image the potential of the prospects throughout the Sacramento Basin. Both Royale and Aspen have used this data to reduce their respective drilling risks. As a result, Royale and Aspen have each achieved a high ratio of productive natural gas wells. However, experience has shown that the prospects drilled in this region have a high level of production for a relatively short period of time, thereby requiring a high level of ongoing drilling activity to sustain reserves, revenue, and income.

Aspen’s declining reserves and lower levels of activity have resulted in a precipitous drop in stock price, from $3.05 per share in January to a low of 52 cents on October 10, 2008. Comparatively, the price of Royale shares has experienced significant upside price movement reaching a 52 week high of $14.70 per share in June 2008, indicating that the potential for stock price growth of Aspen assets under Royale’s management affords a significantly higher value.

Aspen’s common stock is listed on the OTC Bulletin Board, and therefore is not required to comply with much of today’s heightened requirements for corporate governance, disclosure and reporting. Many companies of comparable size voluntarily comply with these requirements. Such voluntary compliance allows for corporate growth in size and listing quality of their common stock. Aspen has not, and has expressed no desire to comply with the more open corporate governance of today’s business environment.

One such basic corporate governance practice is to provide shareholders a voice by announcing and holding annual shareholder meetings. Aspen filed a Form 10-KSB on September 29, 2008 stating that its most recent annual shareholder meeting was held on February 24, 1994. Aspen has failed, for a period of over 14 years, to present shareholders with an opportunity to vote on the direction of the company or express their opinion on management performance and directors responsibility. Aspen’s board of directors has no independent directors, no board committees and no audit committee financial expert.

Regrettably, in January 2008, Aspen’s former CEO and major stockholder, Bob Cohan, suffered a debilitating stroke. On September 10, 2008, Aspen announced that the company was terminating Mr. Cohan’s employment contract. The management of Royale believes the interim management at Aspen has silenced the voice of an important executive and director of the company. Mr. Cohan has been a voice of reason and restraint at Aspen with respect to corporate actions and attitudes toward their shareholders.

Royale desires to protect the value of its common stock holdings in Aspen Exploration, and those of the other independent shareholders from the potential loss of value that will likely result should interim management at Aspen follow through with their stated intentions of liquidating the company assets.

Royale has a good history of expertise and alignment with its shareholders that has provided openness, oversight and increased overall value. A combination between Aspen Exploration into Royale will allow Royale to provide much needed drilling capital to develop Aspen assets. Thus, providing Aspen shareholders a higher value than that which might be achieved should the interim management at Aspen sell its assets.

Royale will commit its resources to the level development activity necessary to realize the value that has been locked away in the oil and gas properties owned by Aspen. Royale’s financial position and its relationships with its vendor and partners will afford full recognition to the potential of these properties, thus ensuring that this value is delivered to shareholders though the ongoing growth of the company.

THE OFFER

Royale is offering to exchange up to 3,992,792 of common stock of Aspen at an exchange ratio of 2.75 shares of Aspen Stock for each share of Royale common stock, upon the terms and subject to the conditions in this prospectus and accompanying letter of transmittal. This offer is referred to in this prospectus as the “exchange offer” or the “offer.” In addition, you will receive cash instead of any fractional shares of Royale common stock to which you may be entitled.

If you are a registered stockholder and tender your shares of Aspen common stock directly to the exchange agent, you will not be obligated to pay any charges or expenses of the exchange agent or any brokerage commissions. If you hold your shares through a broker or bank, you should consult your institution as to whether or not they will charge you any service fees. Except as set forth in the instructions to the revised letter of transmittal, transfer taxes on the exchange of shares of Aspen common stock pursuant to the offer will be paid by Royale.

Extension, Termination and Amendment of the Offer

The offer will expire at 5:00 p.m., New York City time, on ____________ (a date at least 20 business days after commencement of the exchange offer), unless extended to a later date by Royale (the “Expiration Date”). Subject to the rules of the SEC and the terms and conditions of this offer, Royale reserves the right, in its sole discretion, at any time or from time to time, to extend the period of time during which the offer remains open, and Royale can do so by giving oral or written notice of such extension to the exchange agent. If Royal decides to so extend the offer, Royal will make an announcement to that effect no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date. Royale is not making any assurance that it will exercise its right to extend the offer, although it currently intends to do so until all conditions to the offer have been satisfied or waived. During any such extension, all shares of Aspen common stock previously tendered and not withdrawn will remain subject to the offer, subject to your right to withdraw your shares of Aspen common stock. See The Offer—Withdrawal Rights, page 19.

To the extent legally permissible, Royale also reserves the right, in its sole discretion, at any time or from time to time:

to delay acceptance for exchange of, or exchange of, any shares of Aspen common stock pursuant to the offer in order to comply in whole or in part with applicable law;

to waive any condition or otherwise amend the offer in any respect.

Royale will effect any extension, termination, amendment or delay by giving oral or written notice to the exchange agent and by making a public announcement as promptly as practicable thereafter. In the case of an extension, any such announcement will be issued no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date. Subject to applicable law and without limiting the manner in which Royale may choose to make any public announcement, Royale assumes no obligation to publish, advertise or otherwise communicate any such public announcement other than by making a press release.

Royale acknowledges that Rule 14e-1(c) under the Exchange Act requires Royale to pay the consideration offered or return the shares of Aspen common stock tendered promptly after the termination or withdrawal of the offer. Royale will make the exchange offer for a minimum of 20 business days, as required by SEC rules.

Royale confirms to you that if it makes a material change in the terms of the offer or the information concerning the offer, or if it waives a material condition of the offer, it will extend the offer to the extent required under the Exchange Act. If, prior to the expiration date, Royale changes the percentage of shares of Aspen common stock being sought or the consideration offered to you, that change will apply to all holders whose shares of Aspen common stock are accepted for exchange pursuant to Royale’s offer, regardless of whether the shares were tendered before or after the change. If at the time notice of that change is first published, sent or given to you, the offer is scheduled to expire at any time earlier than the tenth business day from and including the date that such notice is first so published, sent or given, Royale will extend the offer until the expiration of that ten business day period. For purposes of the offer, a “business day” means any day other than a Saturday, Sunday or federal holiday and consists of the time period from 12:01 a.m. through 12:00 midnight, New York City time.

Because the offer is for less than all of the outstanding Aspen common stock, SEC Rule 14d-11 does not permit Royale to provide a subsequent offering period after the expiration of the offer.

Exchange of Aspen Shares; Delivery of Royale Common Stock and Cash

Upon the terms and subject to the conditions of the offer (including, if the offer is extended or amended, the terms and conditions of any such extension or amendment), Royale will accept for exchange, and will exchange, up to 3,992,792 shares of Aspen common stock validly tendered and not properly withdrawn promptly after the expiration date. In addition, subject to applicable rules of the SEC, Royale expressly reserves the right to delay acceptance for exchange of, or the exchange of, shares of Aspen common stock in order to comply with any applicable law. In all cases, exchange of shares of Aspen common stock tendered and accepted for exchange pursuant to the offer will be made only after timely receipt by the exchange agent of certificates for those shares of Aspen common stock (or a confirmation of a book-entry transfer of those shares of Aspen common stock in the exchange agent’s account at The Depository Trust Company, referred to as “DTC”), a properly completed and duly executed letter of transmittal and any other required documents.

For purposes of the offer, Royale will be deemed to have accepted for exchange shares of Aspen common stock validly tendered and not properly withdrawn as, if and when it notifies the exchange agent of its acceptance of the tenders of those shares of Aspen common stock pursuant to the offer. The exchange agent will deliver Royale common stock in exchange for shares of Aspen common stock pursuant to the offer and cash instead of fractional shares of Royale common stock promptly after receipt of such notice. The exchange agent will act as your agent for the purpose of receiving Royale common stock (and cash to be paid instead of fractional shares of Royale common stock) from Royale and transmitting such stock and cash to you. You will not receive any interest on any cash that Royale pays you, even if there is a delay in making the exchange.

If Royale does not accept any tendered shares of Aspen common stock for exchange pursuant to the terms and conditions of the offer for any reason (including shares not accepted because of proration), or if certificates are submitted for more shares of Aspen common stock than are tendered, Royale will return certificates for such unexchanged shares of Aspen common stock without expense to the tendering stockholder or, in the case of shares of Aspen common stock tendered by book-entry transfer of such shares of Aspen common stock into the exchange agent’s account at DTC pursuant to the procedures set forth below in The Offer—Procedure for Tendering, page 17, those shares of Aspen common stock will be credited to an account maintained within DTC promptly following expiration or termination of the offer.

Cash Instead of Fractional Shares of Royale Common Stock

Proration

If more than 3,992,792 shares of Aspen common stock are validly tendered and not properly withdrawn prior to the expiration date, Royale will, upon the terms and subject to the conditions of the offer, accept shares for exchange on a pro rata basis. If proration of tendered shares is required, Royale will determine the proration factor promptly following the expiration date. Proration for each stockholder tendering shares will be based on the ratio of the number of shares validly tendered and not properly withdrawn by such stockholder to the total number of shares validly tendered and not properly withdrawn by all stockholders. Because of the difficulty in determining the number of shares validly tendered, including shares tendered by guaranteed delivery procedures as described below, and not properly withdrawn, Royale does not expect that it will be able to announce the final proration factor until five to seven business days after the expiration date. The preliminary results of any proration will be announced by press release promptly after the expiration date. Aspen stockholders may obtain preliminary proration information from the information agent or exchange agent for the offer and may be able to obtain this information from their brokers.

Procedure for Tendering

For you to validly tender shares of Aspen common stock pursuant to the offer, either (a) a properly completed and duly executed letter of transmittal, along with any required signature guarantees, or an agent’s message in connection with a book-entry transfer, and any other required documents, must be received by the exchange agent at one of its addresses set forth on the back cover of this prospectus, and certificates for tendered shares of Aspen common stock must be received by the exchange agent at such address or those shares of Aspen common stock must be tendered pursuant to the procedures for book-entry transfer set forth below (and a confirmation of receipt of such tender, referred to as a “book-entry confirmation,” must be received), in each case before the expiration date, or (b) you must comply with the guaranteed delivery procedures set forth below under The Offer—Guaranteed Delivery, page 18.

The term “agent’s message” means a message transmitted by DTC to, and received by, the exchange agent and forming a part of a book-entry confirmation, which states that DTC has received an express acknowledgment from the DTC participant tendering the shares of Aspen common stock that are the subject of such book-entry confirmation, that such participant has received and agrees to be bound by the terms of the letter of transmittal and that Royale may enforce that agreement against such participant.

Tendering stockholders may use either the revised letter of transmittal and the revised notice of guaranteed delivery circulated with this prospectus or the original letter of transmittal and the original notice of guaranteed delivery previously circulated with the original prospectus. Stockholders using the original letter of transmittal to tender their shares will nevertheless be deemed to be tendering pursuant to the terms and conditions contained in this prospectus and the enclosed revised letter of transmittal.

The exchange agent has established accounts with respect to the shares of Aspen common stock at DTC in connection with the offer, and any financial institution that is a participant in DTC may make book-entry delivery of shares of Aspen common stock by causing DTC to transfer such shares into the exchange agent’s account in accordance with DTC’s procedure for such transfer. However, although delivery of shares of Aspen common stock may be effected through book-entry transfer at DTC, the letter of transmittal with any required signature guarantees, or an agent’s message, along with any other required documents, must, in any case, be received by the exchange agent at one of its addresses set forth on the back cover of this prospectus prior to the expiration date, or the guaranteed delivery procedures described below must be followed. Royale cannot assure you that book-entry delivery of Aspen shares will be available. If book-entry delivery is not available, you must tender Aspen shares by means of delivery of Aspen share certificates or pursuant to the guaranteed delivery procedures set forth below under The Offer—Guaranteed Delivery, page 18.

Signatures on all letters of transmittal must be guaranteed by an eligible institution (as defined below), except (1) in cases in which shares of Aspen common stock are tendered by a registered holder of shares of Aspen common stock who has not completed the box entitled “Special Issuance Instructions” or the box entitled “Special Delivery Instructions” on the letter of transmittal or (2) if shares of Aspen common stock are tendered for the account of a financial institution that is a member of the Securities Transfer Agents Medallion Program or by any other “eligible guarantor institution,” as that term is defined in SEC Rule 17Ad-15 (each of the foregoing is referred to as an “eligible institution”). Most banks, savings and loan associations and brokerage houses are able to effect these signature guarantees for you.

If the certificates for shares of Aspen common stock are registered in the name of a person other than the person who signs the letter of transmittal, or if the offer consideration is to be delivered, or certificates for unexchanged shares of Aspen common stock are to be issued, to a person other than the registered holder(s), the Aspen share certificates must be endorsed or accompanied by appropriate stock powers, in either case signed exactly as the name or names of the registered owner or owners appear on the certificates, with the signature(s) on the certificates or stock powers guaranteed by an eligible institution.

In all cases, Royale will exchange shares of Aspen common stock tendered and accepted for exchange pursuant to the offer only after timely receipt by the exchange agent of certificates for shares of Aspen common stock (or timely confirmation of a book-entry transfer of such securities into the exchange agent’s account at DTC as described above), properly completed and duly executed letter(s) of transmittal (or an agent’s message in connection with a book-entry transfer) and any other required documents.

By executing a letter of transmittal as set forth above, you irrevocably appoint Royale’s designees as your attorneys-in-fact and proxies, each with full power of substitution, to the full extent of your rights with respect to your shares of Aspen common stock tendered and accepted for exchange by Royale and with respect to any and all other shares of Aspen common stock and other securities issued or issuable in respect of the shares of Aspen common stock on or after the expiration date. That appointment is effective, and voting rights will be affected, when and only to the extent that Royale deposits with the exchange agent the shares of its common stock and the cash in lieu of fractional shares in consideration for the shares of Aspen common stock that you have tendered. All such proxies will be considered coupled with an interest in the tendered shares of Aspen common stock and therefore will not be revocable. Upon the effectiveness of such appointment, all prior proxies that you have given will be revoked, and you may not give any subsequent proxies (and, if given, they will not be deemed effective). Royale’s designees will, with respect to the shares of Aspen common stock for which the appointment is effective, be empowered, among other things, to exercise all of your voting and other rights as they, in their sole discretion, deem proper at any annual, special or adjourned meeting of Aspen’s stockholders or otherwise. Royale reserves the right to require that, in order for shares of Aspen common stock to be deemed validly tendered, immediately upon the exchange of those shares, Royale must be able to exercise full voting rights with respect to those shares.

The method of delivery of Aspen share certificates and all other required documents, including delivery through DTC, is at your option and risk, and the delivery will be deemed made only when actually received by the exchange agent. If delivery is by mail, Royale recommends registered mail with return receipt requested, properly insured. In all cases, you should allow sufficient time to ensure timely delivery.

To prevent backup federal income tax withholding, you must provide the exchange agent with your correct taxpayer identification number and certify whether you are subject to backup withholding of federal income tax by completing the substitute Form W-9 included in the letter of transmittal. Some stockholders (including, among others, all corporations and some foreign individuals) are not subject to these backup withholding and reporting requirements. In order for a foreign individual to qualify as an exempt recipient, the stockholder must submit a form W-8BEN, signed under penalties of perjury, attesting to that individual’s exempt status.

Guaranteed Delivery

If you wish to tender shares of Aspen common stock pursuant to the offer and your certificates are not immediately available or you cannot deliver the certificates and all other required documents to the exchange agent prior to the expiration date or complete the procedure for book-entry transfer on a timely basis, your shares of Aspen common stock may nevertheless be tendered, as long as all of the following conditions are satisfied:

you make your tender by or through an eligible institution;

a properly completed and duly executed notice of guaranteed delivery, substantially in the form made available by Royale, is received by the exchange agent as provided below prior to the expiration date; and

the certificates for all tendered shares of Aspen common stock (or a confirmation of a book-entry transfer of such securities into the exchange agent’s account at DTC as described above), in proper form for transfer, together with a properly completed and duly executed letter of transmittal with any required signature guarantees (or, in the case of a book-entry transfer, an agent’s message) and all other documents required by the letter of transmittal, are received by the exchange agent within three trading days after the date of execution of such notice of guaranteed delivery.

You may deliver the notice of guaranteed delivery by hand, overnight courier, facsimile transmission or mail to the exchange agent. The notice must include a guarantee by an eligible institution in the form set forth in the notice.

The tender of shares of Aspen common stock pursuant to any of the procedures described above will constitute a binding agreement between Royale and you upon the terms and subject to the conditions of the offer.

Matters Concerning Validity and Eligibility

Royale will determine all questions as to the validity, form, eligibility (including time of receipt) and acceptance for exchange of any tender of shares of Aspen common stock, in its sole discretion, and its determination will be final and binding to the fullest extent permitted by law. Royale reserves the absolute right to reject any and all tenders of shares of Aspen common stock that it determines are not in proper form or the acceptance of or exchange for which may, in the opinion of its counsel, be unlawful. Royale also reserves the absolute right to waive any defect or irregularity in the tender of any shares of Aspen common stock. No tender of shares of Aspen common stock will be deemed to have been validly made until all defects and irregularities in tenders of shares of Aspen common stock have been cured or waived. None of Royale, the exchange agent, the information agent or any other person will be under any duty to give notification of any defects or irregularities in the tender of any shares of Aspen common stock or will incur any liability for failure to give any such notification. Royale’s interpretation of the terms and conditions of the offer (including the letter of transmittal and instructions thereto) will be final and binding to the fullest extent permitted by law.

If you have any questions about the procedure for tendering shares of Aspen common stock, please contact Royale at its address and telephone numbers set forth on the back cover of this prospectus.

Withdrawal Rights

You can withdraw tendered shares at any time until the offer has expired and, if Royale has not agreed to accept your shares for exchange by the expiration date, you can withdraw them at any time after that date until it accepts shares for exchange. If Royale elects to extend the offer, is delayed in its acceptance for exchange of shares of Aspen common stock or is unable to accept shares of Aspen common stock for exchange pursuant to the offer for any reason, then, without prejudice to Royale’s rights under the offer, the exchange agent may, on behalf of Royale, retain tendered shares of Aspen common stock, and such shares of Aspen common stock may not be withdrawn except to the extent that tendering stockholders are entitled to withdrawal rights as described in this section. Any such delay will be by an extension of the offer to the extent required by law. See The Offer — Extension, Termination and Amendment, page 15.

For a withdrawal to be effective, a written or facsimile transmission notice of withdrawal must be timely received by the exchange agent at one of its addresses set forth on the back cover page of this prospectus. Any such notice of withdrawal must specify the name of the person who tendered the shares of Aspen common stock to be withdrawn, the number of shares of Aspen common stock to be withdrawn and the name of the registered holder of such shares of Aspen common stock, if different from that of the person who tendered such shares of Aspen common stock. If certificates evidencing shares of Aspen common stock to be withdrawn have been delivered or otherwise identified to the exchange agent, then, prior to the physical release of such certificates, the serial numbers shown on such certificates must be submitted to the exchange agent and, unless such shares of Aspen common stock have been tendered by or for the account of an eligible institution, the signature(s) on the notice of withdrawal must be guaranteed by an eligible institution. If shares of Aspen common stock have been tendered pursuant to the procedure for book-entry transfer as set forth in The Offer — Procedure for Tendering, page 17, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn shares of Aspen common stock.

Withdrawals of shares of Aspen common stock may not be rescinded. Any shares of Aspen common stock properly withdrawn will thereafter be deemed not to have been validly tendered for purposes of the offer. However, withdrawn shares of Aspen common stock may be re-tendered by their owner at any time prior to the expiration date by following one of the procedures discussed under The Offer—Procedure for Tendering, page 17, or The Offer—Guaranteed Delivery, page 18.

Royale will decide all questions as to the form and validity (including time of receipt) of any notice of withdrawal in its sole discretion, and its decision shall be final and binding to the fullest extent permitted by law. None of Royale, the exchange agent, the information agent or any other person will be under any duty to give notification of any defects or irregularities in any notice of withdrawal or will incur any liability for failure to give any such notification.

Announcement of Results of the Offer

Royale will announce by press release the final results of the offer, including whether all of the conditions to the offer have been fulfilled or waived and whether Royale will accept the tendered shares of Aspen common stock for exchange, promptly after expiration of the offer, except as otherwise provided above under The Offer – Proration, page 17.

Ownership of Royale After the Offer

On September 30, 2008, 8,505,630 shares of Royale common stock were issued and outstanding, including shares issuable on the exercise of outstanding stock options. Based on the exchange ratio for the offer:

if the maximum of 3,992,792 of Aspen common stock are exchanged for Royale Shares, former Aspen stockholders would own, in the aggregate, approximately 14.584% of the outstanding shares of Royale common stock.

if the minimum of 3,720,036 of Aspen common stock are exchanged for Royale Shares, former Aspen stockholders would own, in the aggregate, approximately 13.72% of the outstanding shares of Royale common stock.

Taxation

The following is a discussion of certain U.S. federal income tax consequences of the offer to holders of Aspen common stock whose stock is exchanged for Royale common stock pursuant to the offer. The discussion is based on the Internal Revenue Code of 1986, as amended, referred to in this prospectus as the “Code,” applicable Treasury Regulations and administrative and judicial interpretations thereof, each as in effect as of the date of this offer, all of which may change, possibly with retroactive effect. The discussion applies only to stockholders who hold their Aspen common stock as capital assets and may not apply to stockholders subject to special rules under the Code, including, without limitation, persons who acquired their Aspen common stock upon the exercise of stock options or otherwise as compensation, financial institutions, brokers, dealers or traders in securities or commodities, insurance companies, partnerships or other entities treated as partnerships or flow-through entities for U.S. federal income tax purposes, tax-exempt organizations, persons who are subject to alternative minimum tax, persons who hold Aspen common stock as a position in a “straddle” or as part of a “hedging” or “conversion” transaction or other integrated investment, or persons that have a functional currency other than the United States dollar. This discussion does not address the U.S. federal tax consequences to any stockholder of Aspen who, for U.S. federal income tax purposes, is a non-resident alien individual, foreign corporation, foreign partnership or foreign estate or trust, and does not address any state, local or foreign tax consequences of the offer.

Because individual circumstances may differ, each stockholder should consult such stockholder’s tax advisor regarding the applicability of the rules discussed below to such stockholder and the particular tax effects to such stockholder of the offer, including the application and effect of state, local, and foreign tax laws.

The receipt of Royale common stock in exchange for Aspen common stock pursuant to the offer is expected to be a taxable transaction for U.S. federal income tax purposes. In general, a stockholder who exchanges Aspen common stock pursuant to the offer will recognize gain or loss for U.S. federal income tax purposes equal to the difference, if any, between the fair market value on the date of acceptance for exchange pursuant to the offer of the Royale common stock received and the holder’s adjusted tax basis in the Aspen common stock exchanged pursuant to the offer. Gain or loss will be determined separately for each block of Aspen common stock (i.e., Aspen common stock acquired at the same cost in a single transaction) exchanged pursuant to the offer. Any such gain or loss generally will be long-term capital gain or loss if the stockholder has held the Aspen common stock for more than one year on the date of acceptance for exchange pursuant to the offer. Long-term capital gain of noncorporate stockholders is generally taxable at a maximum rate of 15%. Certain limitations apply to the use of capital losses.

A holder’s tax basis in the Royale common stock received pursuant to the offer will equal its fair market value on the date of acceptance for exchange pursuant to the offer. A holder’s holding period in the Royale common stock received will begin the day following the date of acceptance for exchange pursuant to the offer.

No Dissenters’ Rights

Dissenters’ rights are the rights of stockholders, in certain cases, to receive “fair value” for their shares, plus accrued interest, as determined by a statutorily prescribed process, which may include a judicial appraisal process. Dissenters’ rights are not available to Aspen shareholders in this offer.

Delaware Business Combination Statute

Section 203 of the DGCL provides for a three-year moratorium on certain business combinations with “interested stockholders” (generally, persons who own, individually or with or through other persons, 15% or more of the corporation’s outstanding voting stock). After the exchange offer, Royale will be an interested person with respect to Aspen. This moratorium, or prohibition, on mergers, consolidations, and other transactions is subject to the following exceptions: (a) the business combination or transaction in which the stockholder becomes an interested stockholder is approved by the board of directors of the corporation prior to the stockholder becoming an interested stockholder; (b) the business combination is with an interested stockholder who became an interested stockholder in a transaction whereby such interested stockholder acquired at least 85% of the corporation’s voting stock, excluding shares held by directors who are also officers and by certain employee stock plans; or (c) the business combination is approved by the corporation’s board of directors and is authorized at a meeting by the affirmative vote of at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder. However, the DGCL permits a corporation to opt out of the restrictions imposed by Section 203 in its certificate of incorporation. Aspen has not opted out of Section 203 in its certificate of incorporation, and accordingly Section 203 will apply to transactions between Royale and Aspen after the exchange offer unless a proposed business combination is approved by Aspen’s board of directors and by a vote of at least two thirds of the outstanding voting stock that is not owned by Royale. Royale has no current plans to enter into a business combination with Aspen after the exchange offer.

Effect of the Offer on the Market for Shares of Aspen Common Stock; Registration Under the Exchange Act; Margin Regulations

Effect of the Offer on the Market for the Shares of Aspen Common Stock

According to Aspen’s Annual Report on Form 10-KSB for the fiscal year ended June 30, 2008, the shares of Aspen common stock are quoted on the OTC Bulletin Board and there were approximately 1,020 holders of record of Aspen common stock as of June 30, 2008. The exchange of shares of Aspen common stock by Royale pursuant to the offer will reduce the number of holders of Aspen common stock and the number of shares of Aspen common stock held by individual holders and could adversely affect the liquidity and market value of the shares of Aspen common stock.

Registration Under the Exchange Act

Based upon Aspen’s public filings with the SEC, Royale believes that Aspen common stock is currently registered under the Exchange Act. Royale does not expect the offer to result in the termination of the registration of the Aspen common stock under the Exchange Act.

Margin Regulations

Aspen common stock is not a “margin security” under the regulations of the Board of Governors of the Federal Reserve System, and is therefore not subject to the margin regulations of the Federal Reserve Board.

Conditions of the Offer

Notwithstanding any other provision of the offer, Royale is not required to accept for exchange or, subject to any applicable rules and regulations of the SEC, including Rule 14e-1(c) under the Exchange Act (relating to Royale’s obligation to pay for or return tendered shares promptly after termination or expiration of the offer), exchange any shares of Aspen common stock, and may terminate or amend the offer, if, at the expiration date, any of the following conditions have not been satisfied or, to the extent legally permissible, waived:

the “registration statement condition”—the registration statement of which this prospectus is a part shall have become effective under the Securities Act, no stop order suspending the effectiveness of the registration statement shall have been issued and no proceedings for that purpose shall have been initiated or threatened by the SEC and Royale shall have received all necessary state securities law or “blue sky” authorizations; and

the “listing condition”— the shares of Royale common stock to be issued pursuant to the offer shall have been authorized for listing on such national securities exchange, subject to official notice of issuance.

the “minimum tender condition”—there shall have been validly tendered and not properly withdrawn prior to the expiration of the offer that number of shares of Aspen common stock representing, together with the shares owned by Royale and its affiliates, at least 48% of the total voting power of all of the outstanding securities of Aspen entitled to vote generally in the election of directors or in a merger, calculated on a fully diluted basis immediately prior to the expiration of the offer;

the “antitrust condition”—any waiting periods under applicable antitrust laws shall have expired or terminated;

the “Aspen debt condition”—Royale shall have received all consents, waivers and approvals required under the terms of Aspen’s indebtedness in order for Royale to consummate the offer; and

the “stockholder approval condition”—Royale’s stockholders shall have approved, as and to the extent required by the rules of any national securities exchange on which the Royale common stock is listed, the issuance of shares of Royale common stock pursuant to the offer.

In addition, notwithstanding any other provision of the offer, Royale is not required to accept for exchange or, subject to any applicable rules and regulations of the SEC, including Rule 14e-1(c) under the Exchange Act (relating to Royale’s obligation to pay for or return tendered shares promptly after termination or expiration of the offer), exchange any shares of Aspen common stock, and may terminate or amend the offer, if, at any time on or after the date of this prospectus and before the expiration of the offer, any of the following conditions exist:

(i)

there is threatened, instituted or pending any action or proceeding by any government, governmental authority or agency or any other person, domestic, foreign or supranational, before any court or governmental authority or agency, domestic, foreign or supranational, (a) challenging or seeking to make illegal, to delay or otherwise, directly or indirectly, to restrain or prohibit the making of the offer, the acceptance for exchange of or exchange of some or all of the shares of Aspen common stock sought by Royale or any of its subsidiaries or affiliates, (b) seeking to obtain material damages or otherwise directly or indirectly relating to the offer, (c) seeking to impose limitations on Royale’s ability or that of any of its subsidiaries or affiliates effectively to exercise any rights as record or beneficial owner of the shares of Aspen common stock acquired or owned by Royale or any of its subsidiaries or affiliates, including, without limitation, the right to vote any shares acquired or owned by Royale or any of its subsidiaries or affiliates on all matters properly presented to Aspen’s stockholders, (d) seeking to require divestiture by Royale or any of its subsidiaries or affiliates of any shares of Aspen common stock, or (e) that otherwise, in Royale’s reasonable judgment, has or may have a material adverse effect on the business, assets, liabilities, financial condition, capitalization, operations or results of operations of Aspen or any of its subsidiaries or affiliates or results or may result in a material diminution in the value of the shares of Aspen common stock; or

(ii)

any action is taken, or any statute, rule, regulation, injunction, order or decree is proposed, enacted, enforced, promulgated, issued or deemed applicable to the offer or the acceptance for exchange of or exchange of shares of Aspen common stock, by any court, government or governmental authority or agency, domestic, foreign or supranational, or of any applicable foreign statutes or regulations (as in effect as of the date of this prospectus) to the offer, that, in Royale’s reasonable judgment, might, directly or indirectly, result in any of the consequences referred to in clauses (a) through (e) of paragraph (i) above; or

(iii)

any change occurs or is threatened (or any development occurs or is threatened involving a prospective change) in the business, assets, liabilities, financial condition, capitalization, operations or results of operations of Aspen or any of its subsidiaries or affiliates that, in Royale’s reasonable judgment, is or may be materially adverse to Aspen or any of its subsidiaries or affiliates or results or may result in a material diminution in the value of the shares of Aspen common stock; or

(iv)

there occurs (a) any general suspension of trading in, or limitation on prices for, securities on any national securities exchange or in the over-the-counter market, (b) any decline in either the Dow Jones Industrial Average, the Standard and Poor’s Index of 500 Industrial Companies or the NASDAQ-100 Index by an amount in excess of 15%, measured from the business day immediately preceding the date of theoffer, or any change in the general political, market, economic or financial conditions in the United States or abroad that, in Royale’s reasonable judgment, could have a material adverse effect on the business, financial condition or results of operations of Aspen and its subsidiaries, taken as a whole, (c) the declaration of a banking moratorium or any suspension of payments in respect of banks in the United States, (d) any material adverse change (or development or threatened development involving a prospective material adverse change) in U.S. or any other currency exchange rates or a suspension of, or a limitation on, the markets therefor, (e) any material adverse change in the market price of the shares of Aspen common stock or in the U.S. securities or financial markets, (f) the commencement of a war, armed hostilities or other international or national calamity directly or indirectly involving the United States or any attack on, outbreak or act of terrorism involving the United States, (g) any limitation (whether or not mandatory) by any governmental authority or agency on, or any other event that, in Royale’s reasonable judgment, may adversely affect, the extension of credit by banks or other financial institutions or (h) in the case of any of the foregoing existing at the time of the date of the amended offer, a material acceleration or worsening thereof; or

(v)

(a) a tender or exchange offer for some or all of the shares of Aspen common stock has been publicly proposed to be made or has been made by another person (including Aspen or any of its subsidiaries or affiliates), or has been publicly disclosed, or any person or “group” (as defined in Section 13(d)(3) of the Exchange Act) has acquired or publicly proposes to acquire beneficial ownership of more than 5% of any class or series of capital stock of Aspen (including Aspen common stock), through the acquisition of stock, the formation of a group or otherwise, or is granted any option, right or warrant, conditional or otherwise, to acquire beneficial ownership of more than 5% of any class or series of capital stock of Aspen (including Aspen common stock) other than acquisitions for bona fide arbitrage purposes only and other than as disclosed in a Schedule 13D or 13G on file with the SEC on the date of this prospectus, (b) any such person or group which, prior to the date of this prospectus, had filed such a Schedule with the SEC has acquired or proposes to acquire beneficial ownership of additional shares of any class or series of capital stock of Aspen, through the acquisition of stock, the formation of a group or otherwise, constituting 1% or more of any such class or series, or is granted any option, right or warrant, conditional or otherwise, to acquire beneficial ownership of additional shares of any class or series of capital stock of Aspen constituting 1% or more of any such class or series, (c) any person or group has entered into a definitive agreement or an agreement in principle or made a proposal with respect to a tender or exchange offer or a merger, consolidation or other business combination with or involving Aspen or (d) any person has filed a Notification and Report Form under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, or made a public announcement reflecting an intent to acquire Aspen or any assets or securities of Aspen; or

(vi)

Aspen or any of its subsidiaries has (a) split, combined or otherwise changed, or authorized or proposed the split, combination or other change of, the shares of Aspen common stock or its capitalization, (b) acquired or otherwise caused a reduction in the number of, or authorized or proposed the acquisition or other reduction in the number of, outstanding shares of Aspen common stock or other securities, (c) issued or sold, or authorized or proposed the issuance or sale of, any additional shares of Aspen common stock, shares of any other class or series of capital stock, other voting securities or any securities convertible into, or options, rights or warrants, conditional or otherwise, to acquire, any of the foregoing (other than the issuance of shares of Aspen common stock or options to employees or directors in the ordinary course of business consistent with past practice), or any other securities or rights in respect of, in lieu of, or in substitution or exchange for any shares of its capital stock, (d) permitted the issuance or sale of any shares of any class of capital stock or other securities of any subsidiary of Aspen, (e) declared, paid or proposed to declare or pay any dividend or other distribution on any shares of capital stock of Aspen, (f) altered or proposed to alter any material term of any outstanding security, issued or sold, or authorized or proposed the issuance or sale of, any debt securities or otherwise incurred or authorized or proposed the incurrence of any debt other than in the ordinary course of business, (g) authorized, recommended, proposed, announced its intent to enter into or entered into an agreement with respect to or effected any merger, consolidation, liquidation, dissolution, business combination, acquisition of assets, disposition of assets or relinquishment of any material contract or other right of Aspen or any of its subsidiaries or any comparable event not in the ordinary course of business, (h) authorized, recommended, proposed, announced its intent to enter into or entered into any agreement or arrangement with any person or group that, in Royale’s reasonable judgment, has or may have a material adverse effect on the business, assets, liabilities, financial condition, capitalization, operations or results of operations of Aspen or any of its subsidiaries or affiliates or results or may result in a material diminution in the value of the shares of Aspen common stock, (i) entered into or amended any employment, severance or similar agreement, arrangement or plan with any of its employees other than in the ordinary course of business or entered into or amended any such agreements, arrangements or plans so as to provide for increased benefits to employees as a result of or in connection with the making of the offer or the acceptance for exchange of or exchange of some of or all the shares of Aspen common stock sought by Royale, (j) except as may be required by law, taken any action to terminate or amend any employee benefit plan (as defined in Section 3(2) of the Employee Retirement Income Security Act of 1974) of Aspen or any of its subsidiaries, or (k) amended, or authorized or proposed any amendment to, its articles of incorporation or bylaws (or other similar constituent documents); or

(vii)

(a) any material contractual right of Aspen or any of its subsidiaries has been impaired or otherwise adversely affected or any material amount of indebtedness of Aspen or any of its subsidiaries has been accelerated or has otherwise become due or become subject to acceleration prior to its stated due date, in each case with or without notice or the lapse of time or both, as a result of or in connection with the offer or (b) any covenant, term or condition in any instrument or agreement of Aspen or any of its subsidiaries, in Royale’s reasonable judgment, has or may have a material adverse effect on the business, assets, liabilities, financial condition, capitalization, operations or results of operations of Aspen or any of its subsidiaries or affiliates or results or may result in a material diminution in the value of the shares of Aspen common stock (including, without limitation, any event of default that may ensue as a result of or in connection with the offer or the acceptance for exchange of or exchange of some or all of the shares of Aspen common stock sought by Royale); or

(viii)

Royale or any of its affiliates enters into a definitive agreement or announces an agreement in principle with Aspen providing for a merger or other similar business combination with Aspen or any of its subsidiaries or the purchase of securities or assets of Aspen or any of its subsidiaries, or Royale and Aspen reach any other agreement or understanding pursuant to which it is agreed that the offer will be terminated; or

(ix)

Aspen or any of its subsidiaries shall have (a) granted to any person proposing a merger or other business combination with or involving Aspen or any of its subsidiaries or the purchase of securities or assets of Aspen or any of its subsidiaries any type of option, warrant or right which, in Royale’s reasonable judgment, constitutes a “lock-up” device (including, without limitation, a right to acquire or receive any shares of Aspen common stock or other securities, assets or business of Aspen or any of its subsidiaries) or (b) paid or agreed to pay any cash or other consideration to any party in connection with or in any way related to any such business combination or purchase; which, in Royale’s reasonable judgment, in any such case, makes it inadvisable to proceed with such acceptance for exchange or exchange.

The satisfaction or existence of any of the conditions to the offer will be determined by Royale in its sole discretion. These conditions are for the sole benefit of Royale and its affiliates and may be asserted by Royale in its sole discretion regardless of the circumstances giving rise to any of these conditions or may be waived (to the extent legally permissible) by Royale in its sole discretion in whole or in part at any time or from time to time before the expiration date (provided that all conditions to the offer must be satisfied or waived prior to the expiration of the offer). Royale expressly reserves the right to waive any of the conditions to the offer (to the extent legally permissible) and to make any change in the terms of or conditions to the offer. Royale’s failure at any time to exercise its rights under any of these conditions will not be deemed a waiver of any such right. The waiver of any such right with respect to particular facts and circumstances will not be deemed a waiver with respect to any other facts and circumstances. Each such right will be deemed an ongoing right which may be asserted at any time or from time to time, except that any such right may not be asserted after the expiration date. Any determination made by Royale concerning the events described in this section will be final and binding upon all parties, subject to the tendering stockholder’s right to bring any dispute with respect thereto before a court of competent jurisdiction.

Dividends and Distributions

If on or after the date of this prospectus, Aspen:

(a) splits, combines or otherwise changes its shares of common stock or its capitalization,

(b) acquires shares of its common stock or otherwise causes a reduction in the number of outstanding shares,

(c) issues or sells any additional shares of its common stock (other than shares or options issued to employees or directors in the ordinary course of business consistent with past practice), shares of any other class or series of capital stock, other voting securities or any securities convertible into, or options, rights, or warrants, conditional or otherwise, to acquire, any of the foregoing, or any other securities or rights in respect of, in lieu of, or in substitution or exchange for any shares of its capital stock, or

(d) discloses that it has taken such action,

then, without prejudice to Royale’s rights under The Offer—Extension, Termination and Amendment and —Conditions of the Offer, Royale may, in its sole discretion, make such adjustments in the exchange ratio and other terms of the offer as it deems appropriate including, without limitation, the number or type of securities to be purchased.

Certain Legal Matters; Regulatory Approvals

General

Royale is not aware of any governmental license or regulatory permit that appears to be material to Aspen’s business that might be adversely affected by Royale’s acquisition of shares of Aspen common stock pursuant to the offer or of any approval or other action by any government or governmental administrative or regulatory authority or agency, domestic or foreign, that would be required for Royale’s acquisition or ownership of shares of Aspen common stock pursuant to the offer. Should any of these approvals or other actions be required, Royale currently contemplates that these approvals or other actions will be sought. There can be no assurance that any of these approvals or other actions, if needed, will be obtained (with or without substantial conditions) or that if these approvals were not obtained or these other actions were not taken adverse consequences might not result to Royale, Aspen or any of their respective subsidiaries, which could result in the failure of a condition to the offer. Royale’s obligation under the offer to accept for exchange and exchange shares of Aspen common stock is subject to certain conditions. See The Offer—Conditions of the Offer, page 22.

Antitrust

Royale does not believe that the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, is applicable to the proposed transaction. Nevertheless, the Antitrust Division of the Department of Justice, referred to in this prospectus as the “Antitrust Division,” and the Federal Trade Commission, referred to in this prospectus as the “FTC,” frequently scrutinize the legality under the antitrust laws of transactions such as Royale’s acquisition of shares pursuant to the offer. At any time before or after the consummation of any such transactions, the Antitrust Division or the FTC could take such action under the antitrust laws as it deems necessary or desirable in the public interest, including seeking to enjoin the purchase of shares pursuant to the offer or seeking divestiture of the shares so acquired or divestiture of Royale’s or Aspen’s material assets. Private parties (including individual states) may also bring legal actions under the antitrust laws. Based on an examination of the publicly available information relating to the business in which Aspen is engaged, Royale does not believe that the consummation of the offer will result in a violation of any applicable antitrust laws. However, there can be no assurance that a challenge to the offer on antitrust grounds will not be made or, if such a challenge is made, what the result will be. See “Conditions of the Offer” for certain conditions to the offer, including conditions with respect to litigation and certain governmental actions.

Relationships with Aspen

Except as set forth in this prospectus, neither Royale nor any of its affiliates nor, to the best of its knowledge, any of its directors or executive officers has any contract, arrangement, understanding or relationship with any other person with respect to any securities of Aspen, including, but not limited to, any contract, arrangement, understanding or relationship concerning the transfer or the voting of any securities, joint ventures, loan or option arrangements, puts or calls, guaranties of loans, guaranties against loss or the giving or withholding of proxies. Except as otherwise described in this prospectus, during the two years before the date of this prospectus, there have been no contracts, negotiations or transactions between Royale, any of its affiliates or, to the best of its knowledge, any of the persons listed on Schedule I to this prospectus, and Aspen or its affiliates, on the other hand, concerning a merger, consolidation or acquisition, an exchange offer or other acquisitions of securities, election of directors, or sale or other transfer of a material amount of assets. See, Background of the Offer, page 12.

As of the date of this prospectus, Royale beneficially owned 353,125 of Aspen common stock, representing approximately 4.86% of the outstanding shares of Aspen common stock, based on 7,259,622 shares reported by Aspen to be outstanding as of June 30, 2008. None of Royale’s affiliates beneficially owns any shares of Aspen common stock.

Source and Amount of Funds

Royale estimates that the total amount of cash required to complete the transactions contemplated by the offer, including payment of cash in lieu of fractional shares and payment of fees and expenses related to the transactions, will be approximately $60,000. Royale intends to pay these costs from its available cash on hand.

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS OF ROYALE AND ASPEN

PRO FORMA BALANCE SHEETS

	Royale		Aspen		Combined			Royale		Aspen		Combined
	September 30,		September 30,		September 30,			December 31,		December 31,		December 31,
	2008		2008		2008			2007		2007		2007
	(Unaudited)		(Unaudited)		(Unaudited)			(Unaudited)		(Unaudited)		(Unaudited)

ASSETS

Current Assets
Cash and Cash Equivalents	$	6,663,717	$	1,748,667	$	8,412,384		$	3,848,968	$	2,741,531	$	6,590,499
Accounts Receivable		4,542,624		1,770,131		6,312,755			4,090,341		2,363,518		6,453,859
Prepaid Expenses		1,231,933		263,650		1,495,583			673,453		263,650		937,103
Deferred Tax Asset		217,586		1,488,500		1,706,086			217,586		2,174,000		2,391,586
Inventory		182,219				182,219			344,339				344,339
Marketable Securities		177,533		410,673		410,673	A		0		1,258,810		1,258,810
Other Current Assets				41,244		41,244					43,539		43,539

Total Current Assets		13,015,612		5,722,865		18,560,944			9,174,687		8,845,048		18,019,735

Property and Equipment, net of depreciation, depletion, and amortization, and impairment
Oil and Gas Properties, at cost, (successful efforts basis),
Equipment and Fixtures		21,756,031				21,756,031			23,389,741				23,389,741
Oil and Gas Property (full cost basis)				12,724,857		12,724,857					12,912,744		12,912,744
Support Equipment				107,485		107,485					112,768		112,768

Total Net Property and Equipment		21,756,031		12,832,342		34,588,373			23,389,741		13,025,512		36,415,253

Other Assets		6,946		0		6,946			6,946				6,946

Total Assets	$	34,778,589	$	18,555,207	$	53,156,263		$	32,571,374	$	21,870,560	$	54,441,934

ROYALE ENERGY, INC.

PRO FORMA BALANCE SHEETS

	Royale			Aspen			Combined			Royale			Aspen			Combined
	September 30,			September 30,			September 30,			December 31,			December 31,			December 31,
	2008			2008			2008			2007			2007			2007
	(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
Accounts Payable and Accrued Expenses	$	5,001,620		$	1,963,000		$	6,964,620		$	10,080,034		$	4,641,395		$	14,721,429
Current Portion of Long-Term Debt		0			453,180			453,180			0			275,000			275,000
Deferred Revenue from Turnkey Drilling		8,152,540						8,152,540			3,947,097			0			3,947,097
Asset Retirement Obligation, current portion					40,200			40,200						43,000			43,000
Deferred Income Taxes, current					0			0						252,000			252,000

Total Current Liabilities		13,154,160			2,456,380			15,610,540			14,027,131			5,211,395			19,238,526

Noncurrent Liabilities:
Asset Retirement Obligation		429,961			605,800			1,035,761			402,278			557,998			960,276
Deferred Tax Liability		1,172,030			3,873,500			5,061,327	A		581,181			4,377,500			4,958,681
Long-Term Debt, Net of Current Portion		2,575,974			66,667			2,642,641			5,175,974			454,167			5,630,141

Total Noncurrent Liabilities		4,177,965			4,545,967			8,739,729			6,159,433			5,389,665			11,549,098

Total Liabilities		17,332,125			7,002,347			24,350,269			20,186,564			10,601,060			30,787,624

Stockholders' Equity:
Common Stock, no par value, authorized 10,000,000 shares,8,538,717 and 7,951,746 shares issued; 8,503,448 and 7,918,659 shares outstanding, respectively		23,355,926						23,355,926			19,511,963						19,511,963
Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At September 30, 2008 and December 31, 2007 7,259,622 shares					36,298			36,298						36,298			36,298
Convertible preferred stock, Series AA, no par value,147,500 shares authorized; 52,784 and 57,416 shares issued and outstanding, respectively		154,014						154,014			167,979						167,979
Accumulated Deficit/Retained Earnings		(5,934,434	)		4,385,879			(1,548,555	)		(7,140,695	)		3,779,914			(3,360,781	)

Total Paid in Capital and Accumulated Deficit		17,575,506			4,422,177			21,997,683			12,539,247			3,816,212			16,355,459
Less Cost of Treasury Stock 33,087 and 33,087 shares		(181,012	)					(405,008	) A		(181,012	)					(181,012	)
Additional Paid in Capital		82,636			7,676,458			7,759,094			26,575			7,549,087			7,575,662
Accumlated Other Comprehensive Income		(30,666	)		(545,775	)		(545,775	) A		0			(95,799	)		(95,799	)
Dividend to be Distributed																	0
Total Stockholders' Equity		17,446,464			11,552,860			28,805,994			12,384,810			11,269,500			23,654,310
Total Liabilities and Stockholders' Equity	$	34,778,589		$	18,555,207		$	353,156,263		$	32,571,374		$	21,870,560		$	54,441,934

The Combined amounts for 2008's marketable securities, deferred tax liability, treasury stock, and accumulated other comprehensive income were adjusted to reflect the combination of the two companies. At September 30, 2008 Royale's marketable securities were stock investments in Aspen, and were reported as available for sale securities that included adjustments relating to the securities’ fair value computation. For the purposes of this Pro Forma Balance Sheet, Royale's 113,803 shares of Aspen are reported as treasury stock in the Combined column. Due to these adjustments, the noted amounts do not cross foot.

ROYALE ENERGY, INC.

PRO FORMA STATEMENTS OF OPERATIONS

FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2007

	Royale			Aspen			Combined
	2007			2007			2007
	(Audited)			(Unaudited)			(Unaudited)

Revenues:
Sale of Oil and Gas	$	6,110,092		$	4,987,056		$	11,097,148
Turnkey drilling		9,408,103						9,408,103
Supervisory Fees and Other		1,039,204			694,491			1,733,695

Total Revenues		16,557,399			5,681,547			22,238,946

Costs and Expenses:
General and Administrative		4,712,624			1,028,009			5,740,633
Turnkey Drilling and Development		4,977,811						4,977,811
Geological and Geophysical Expense		423,459						423,459
Lease Operating		2,116,977			1,183,716			3,300,544
Lease Impairment		2,106,670						2,106,670
Legal and Accounting		928,628						928,628
Marketing		1,455,296						1,455,296
Depreciation, Depletion and Amortization		3,585,682			2,401,487			5,987,169

Total Costs and Expenses		20,307,147			4,613,212			24,920,210

Gain (Loss) on Sale of assets		(135,396	)					(135,396	)

Income (Loss) From Operations		(3,885,144	)		1,068,335			(2,816,660	)

Other Income (Expense):
Interest expense		(152,547	)					(152,547	)
Interest and Other Expense					(68,800	)		(68,800	)
Gain on investments					227,182			227,182

Total Other Income (Expense)		(152,547	)		158,382			5,835

Income (Loss) Before Income Tax Expense		(4,037,691	)		1,226,717			(2,810,825	)
Income Tax Provision (Benefit)		(1,258,484	)		607,415		$	(650,919	)

Net Income Before Cumulative Effect of Accounting Change		(2,779,207	)		619,302			(2,159,906	)
Cumulative Effect of Accounting Change		0			0			0

Net Income (Loss)	$	(2,779,207	)	$	619,302		$	(2,159,906	)

Basic Earnings Per Share:
Net Income available to common stock	$	(0.35	)	$	0.08		$	(0.27	)

Cumulative Effect of Accounting Change		-			-			-


Diluted Earnings Per Share	$	(0.35	)	$	0.08		$	(0.27	)

Pro Forma Condensed Statements of Comprehensive Income

For the twelve months ended December 31, 2007

Net Income	$	(2,779,207	)	$	619,302		$	(2,159,906	)

Unrealized losses on available-for-sale securities		-			(161,675	)		(161,675	)
Income Tax Expense (Benefit) Related to Items of Other Comprehensive Income		-			65,876			65,876
Other Comprehensive Income, net of tax		-			(95,799	)		(95,799	)
Comprehensive Income (loss)	$	(2,779,207	)	$	523,503		$	(2,255,705	)

ROYALE ENERGY, INC.

PRO FORMA STATEMENTS OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008

	Royale			Aspen			Combined			Royale			Aspen			Combined
	2008			2008			2008			2007			2007			2007
	(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)

Revenues:
Sale of Oil and Gas	$	5,835,278		$	4,097,887		$	9,933,165		$	4,552,179		$	3,622,281		$	8,174,460
Turnkey drilling		6,269,545						6,269,545			6,021,892						6,021,892
Supervisory Fees and Other		554,323			553,977			1,108,300			791,225			604,868			1,396,093

Total Revenues		12,659,146			4,651,864			17,311,010			11,365,296			4,227,149			15,592,445

Costs and Expenses:
General and Administrative		3,041,235			1,125,973			4,167,208			3,345,386			896,339			4,241,725
Turnkey Drilling and Development		2,926,379						2,926,379			2,956,819						2,956,819
Geological and Geophysical Expense		0						-			0						-
Lease Operating		1,861,884			1,192,306			3,054,190			1,970,147			772,831			2,742,978
Lease Impairment		820,966						820,966			34,894						34,894
Legal and Accounting		1,067,197						1,067,197			629,480						629,480
Marketing		916,625						916,625			1,080,631						1,080,631
Depreciation, Depletion and Amortization		2,601,622			1,620,645			4,222,267			2,905,024			1,701,044			4,606,068

Total Costs and Expenses		13,235,908			3,938,924			17,174,832			12,922,381			3,370,214			16,292,595

Gain (Loss) on Sale of assets		2,602,577			0			2,602,577			(44,931	)					(44,931	)

Income From Operations		2,025,815			712,940			2,738,755			(1,602,016	)		856,935			(745,081	)

Other Income (Expense):
Interest expense		(195,408	)					(195,408	)		(116,435	)					(116,435	)
Interest and Other Expense					(44,392	)		(44,392	)					(50,276	)		(50,276	)
Gain on investments					16,884			16,884						227,182			227,182

Total Other Income (Expense)		(195,408	)		(27,508	)		(222,916	)		(116,435	)		176,906			60,471

Income Before Income Tax Expense		1,830,407			685,432			2,515,839			(1,718,451	)		1,033,841			(684,610	)
Income Tax Provision (Benefit)		624,146			79,467		$	703,613			(579,966	)		576,761		$	(3,205	)

Net Income Before Cumulative Effect of Accounting Change		1,206,261			605,965			1,812,226			(1,138,485	)		457,080			(681,405	)
Cumulative Effect of Accounting Change		0			0			0			0			0			0

Net Income (Loss)	$	1,206,261		$	605,965		$	1,812,226		$	(1,138,485	)	$	457,080		$	(681,405	)

Basic Earnings Per Share:
Net Income available to common stock	$	0.15		$	0.09		$	0.24		$	(0.14	)	$	0.06		$	(0.08	)

Cumulative Effect of Accounting Change		-			-			-									-

Diluted Earnings Per Share	$	0.15		$	0.08		$	0.23		$	(0.14	)	$	0.06		$	(0.08	)

Condensed Statements of Comprehensive Income

For the nine months ended September 30, 2008

	Royale			Aspen			Combined			Royale			Aspen			Combined
		2008			2008			2008			2007			2007			2007

Net Income	$	1,206,261		$	605,965		$	1,812,226		$	(1,138,485	)	$	457,080		$	(681,405	)

Unrealized losses on available-for-sale securities		(46,463	)		(749,018	)		(749,018	)		-			(281,618	)		(281,618	)
Income Tax Expense (Benefit) Related to Items of Other Comprehensive Income		15,797			301,943			301,943			-			114,748			114,748
Other Comprehensive Income, net of tax		(30,666	)		(447,075	)		(477,741	)		-			(166,870	)		(166,870	)

Comprehensive Income (loss)	$	1,175,595		$	158,890		$	1,334,485		$	(1,138,485	)	$	290,210		$	(848,275	)

Notes to Combined Pro Forma Statements of Operations

1. The notes relating to the previously filed periods are an integral part of these condensed consolidated financial statements, and are filed with the Securities and Exchange Commission as either a 10K or 10Q.

2. For the purposes of these Pro Forma financial statements, the items below were adjusted when estimating the effects of the combination.

2a. Income Statement

1. Using the notes accompanying Aspen's financial statement, we were able to remove Aspen's well management fees from their selling, general, and administrative operating expense line, and include the amount in revenue's supervisory fees and other.

2. Within Royale's financial statements, interest and other income are included in the supervisory fees and other amount under revenue, and as such, Aspen's interest and other income was included in the supervisory and fees and other amount.

3. Aspen's legal, accounting, and marketing expenses are included in these statements' general and administrative expense. There are no notes within Aspen's financial statement where a reasonable estimate of these costs can be calculated and listed in their separate line items.

4. (A) Due to those adjustments noted on the balance sheet in note (A), the noted amounts do not cross foot.

2b. Balance Sheet

1. Aspen's deposits and deferred income taxes, listed as other assets, were reported as prepaid expenses and deferred tax asset, respectively.

ROYALE’S BUSINESS

Royale, like Aspen, is an independent oil and natural gas producer. Royale's principal lines of business are the production and sale of natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale. Royale was incorporated in California in 1986 and began operations in 1988. Royale's common stock is traded on the Nasdaq Global Market (symbol ROYL). On December 31, 2007, Royale had 24 full time employees.

Royale owns wells and leases located mainly in the Sacramento Basin and San Joaquin Basin in California as well as in Utah, Texas and Louisiana. Royale usually sells a portion of the working interest in each lease that it acquires to third party investors and retains a portion of the prospect for its own account. Selling part of the working interest to others allows Royale to reduce its drilling risk by owning a diversified inventory of properties with less of its own funds invested in each drilling prospect, than if Royale owned the whole working interest and paid all drilling and development costs of each prospect itself. Royale generally sells working interests in its prospects to accredited investors in exempt securities offerings. The prospects are bundled into multi-well investments, which permit the third party investors to diversify their investments by investing in several wells at once instead of investing in single well prospects.

During its fiscal year ended December 31, 2007, Royale continued to explore and develop natural gas properties in northern California and Utah. We also own proved developed producing reserves of oil and natural gas in Texas and Louisiana. Royale drilled seven wells in 2007, four of which are currently commercially productive wells, and two are being tested. Royale's estimated total reserves decreased from approximately 8.5 Bcfe (billion cubic feet equivalent) at December 31, 2006 to approximately 4.0 Bcfe at December 31, 2007. According to the reserve report furnished to Royale by Netherland, Sewell & Associates, Inc., Royale's independent petroleum engineers, the net reserve value of its proved developed and undeveloped reserves was approximately $19.9 million at December 31, 2007, based on natural gas prices ranging from $3.83 per Mcf to $7.77 per Mcf. Of course, net reserve value does not represent the fair market value of our reserves on that date, and we cannot be sure what return we will eventually receive on our reserves. Net reserve value of proved developed and undeveloped reserves was calculated by subtracting estimated future development costs, future production costs and other operating expenses from estimated net future cash flows from our developed and undeveloped reserves.

Our standardized measure of discounted future net cash flows at December 31, 2007, was estimated to be $10,644,882. This figure was calculated by subtracting our estimated future income, tax expense from the net reserve value of proved and undeveloped reserves, and by further applying a 10% annual discount for estimated timing of cash flows. A detailed calculation of our standardized measure of discounted future net cash flow is contained in our financial statements under Supplemental Information About Oil and Gas Producing Activities – Changes in Standardized Measure of Discounted Future Net Cash Flow from Proved Reserve Quantities.

Royale reported gross revenues in connection with the drilling of wells on a "turnkey contract" basis, or sales of fractional interests in undeveloped wells, in the amount of $9,408,103 for the year ended December 31, 2007, which represents 57% of its total revenues for the year. In 2006, Royale reported $15,711,550 gross revenues from turnkey drilling operations for the year, representing 63% of Royale's total revenues for that year.

These amounts are offset by drilling expenses and development costs of $4,977,811 in 2007, and $9,628,394 in 2006. In addition to Royale's own geological, land, and engineering staff, Royale hires independent contractors to drill, test, complete and equip the wells that it drills.

Approximately 37% of Royale's total revenue for the year ended December 31, 2007 came from sales of oil and natural gas from production of its wells in the amount of $6,110,092. In 2006, this amount was $7,965,633, which represented 32% of Royale's total revenues.

Plan of Business

Royale acquires interests in oil and natural gas reserves and sponsors private joint ventures. Royale believes that its stockholders are better served by diversification of its investments among individual drilling prospects. Through its sale of joint ventures, Royale can acquire interests and develop oil and natural gas properties with greater diversification of risk and still receive an interest in the revenues and reserves produced from these properties. By selling some of its working interest in most projects, Royale decreases the amount of its investment in the projects and diversifies its oil and gas property holdings, to reduce the risk of concentrating a large amount of its capital in a few projects that may not be successful.

After acquiring the leases or lease participation, Royale drills or participates in the drilling of development and exploratory oil and natural gas wells on its property. Royale pays its proportionate share of the actual cost of drilling, testing, and completing the project to the extent that it retains all or any portion of the working interest.

Royale also may sell fractional interests in undeveloped wells to finance part of the drilling cost. A drilling contract that calls for a company to drill a well, for a fixed price, to a specified depth or geological formation is called a "turnkey contract." When Royale sells fractional interests to raise capital to drill oil and natural gas wells, generally it agrees to drill these wells on a turnkey contract basis, so that the holders of the fractional interests prepay a fixed amount for the drilling and completion of a specified number of wells. Under a turnkey contract, Royale recognizes gross revenue for the amount paid by the purchaser and agrees to pay the expense of drilling and development of the well for the participants. Sometimes the actual drilling and development costs are less than the fixed amount that Royale received from the fractional interest sale.

When Royale authorizes a turnkey drilling project for sale, a calculation is made to estimate the pre-drilling costs and the drilling costs. A percentage for each is calculated. The turnkey drilling project is then sold to investors who execute a contract with Royale. In this agreement, the investor agrees to share in the pre-drilling costs, which include lease costs, geological and geophysical costs, and other costs as required so that the drilling of the project can proceed. As stated in the contract, the percentage of the pre-drilling costs that the investor contributes is non-refundable, and thus on its financial statements, Royale recognizes these non-refundable payments as revenue since the pre-drilling costs have commenced. The remaining investment is held and reported by Royale as deferred revenue until drilling is complete.

Drilling is generally completed within 10-30 days. See Note 1 to Royale's Financial Statements. Royale maintains internal records of the expenditure of each investor's funds for drilling projects.

Royale generally operates the wells it completes. As operator, it receives fees set by industry standards from the owners of fractional interests in the wells and from expense reimbursements. For the year ended December 31, 2007, Royale earned gross revenues from operation of the wells in the amount of $400,897, representing 2.4% of its total revenues on a consolidated basis for that year. In 2006, the amount was $484,615, which represented about 1.9% of total revenues. At December 31, 2007, Royale operated 54 natural gas wells in California. Royale also owns an interest and operates two natural gas wells in Utah and has non-operating interests in 17 oil and gas wells in Texas, three in Oklahoma, two in California, and two in Louisiana.

Royale currently sells most of its California natural gas production through PG&E pipelines to independent customers on a monthly contract basis, while some gas is delivered through privately owned pipelines to independent customers. Generally we sell an entire month’s production to the highest bidder. Because many users are willing to make such purchase arrangements, the loss of any one customer would not affect our overall sales operations.

All oil and natural gas properties are depleting assets in which production naturally decreases over time as the finite amount of existing reserves are produced and sold. It is Royale’s business as an oil and natural gas exploration and production company to continually search for new development properties. The company’s success will ultimately depend on its ability to continue locating and developing new oil and natural gas resources.

Natural gas demand and the prices paid for gas are seasonal. In recent years, natural gas demand and prices in Northern California have fluctuated unpredictably throughout the year.

Royale has no subsidiaries.

Competition, Markets and Regulation

Competition

The exploration and production of oil and natural gas is an intensely competitive industry. The sale of interests in oil and gas projects, like those Royale sells, is also very competitive. Royale encounters competition from other oil and natural gas producers, as well as from other entities which invest in oil and gas for their own account or for others, and many of these companies are substantially larger than Royale.

Markets

Market factors affect the quantities of oil and natural gas production and the price Royale can obtain for the production from its oil and natural gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental, energy conservation, and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry.

Regulation

Federal and state laws and regulations affect, to some degree, the production, transportation, and sale of oil and natural gas from Royale’s operations. States in which Royale operates have statutory provisions regulating the production and sale of oil and natural gas, including provisions regarding deliverability. These statutes, along with the regulations interpreting the statutes, generally are intended to prevent waste of oil and natural gas, and to protect correlative rights to produce oil and natural gas by assigning allowable rates of production to each well or proration unit.

The exploration, development, production and processing of oil and natural gas are subject to various federal and state laws and regulations to protect the environment. Various federal and state agencies are considering, and some have adopted, other laws and regulations regarding environmental controls that could increase the cost of doing business. These laws and regulations may require: the acquisition of a permit by operators before drilling commences; the prohibition of drilling activities on certain lands lying within wilderness areas or where pollution arises; and the imposition of substantial liabilities for pollution resulting from drilling operations, particularly operations in offshore waters or on submerged lands. The cost of oil and natural gas development and production also may increase because of the cost of compliance with such legislation and regulations, together with any penalties resulting from failing to comply with the legislation and regulations. Ultimately, Royale may bear some of these costs.

Presently, Royale does not anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect on capital expenditures, earnings, or its competitive position in the oil and natural gas industry; however, changes in the laws, rules or regulations, or the interpretation thereof, could have a materially adverse effect on Royale’s financial condition or results of operation.

ROYALE’S PROPERTIES

Since 1993, Royale Energy has concentrated on development of properties in the Sacramento Basin and the San Joaquin Basin of Northern and Central California. In 2007, Royale Energy drilled four wells in northern and central California, three of which were commercially productive wells and are currently producing. We also drilled three wells in Utah, one of which is commercially productive and two others are being tested, but due to weather conditions in the Rockies, full results have been delayed.

Following industry standards, Royale Energy generally acquires oil and natural gas acreage without warranty of title except as to claims made by, through, or under the transferor. In these cases, Royale Energy attempts to conduct due diligence as to title before the acquisition, but it cannot assure that there will be no losses resulting from title defects or from defects in the assignment of leasehold rights. Title to property most often carries encumbrances, such as royalties, overriding royalties, carried and other similar interests, and contractual obligations, all of which are customary within the oil and natural gas industry.

Royale Energy maintains a revolving credit agreement with Guaranty Bank, FSB. Under the terms of the agreement, from time to time, Royale Energy may borrow, repay, and reborrow money from Guaranty Bank with a total credit line of $15,000,000. The maximum allowable amount of each credit request is governed by a formula in the agreement. The maximum allowable amount at December 31, 2007, was $5,375,974. At December 31, 2007, Royale Energy owed $5,175,974 under this credit line. Royale uses advances under this credit line to finance lease acquisition operations and for temporary working capital. Following is a discussion of Royale Energy's significant oil and natural gas properties. Reserves at December 31, 2007, for each property discussed below, have been determined by Netherland, Sewell & Associates, Inc., registered professional petroleum engineers, in accordance with its report submitted to Royale Energy on February 7, 2008.

Northern California

Royale Energy owns lease interests in ten gas fields with locations ranging from Tehama County in the north to Kern County in the south, in the Sacramento and San Joaquin Basins in California. At December 31, 2007, Royale operated 54 wells in California with estimated total proven, developed, and undeveloped reserves at approximately 3.0 bcf, according to Royale’s independently prepared reserve report as of December 31, 2007.

Developed and Undeveloped Leasehold Acreage

As of December 31, 2007, Royale Energy owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.

	Developed Gross Acres		Net Acres		Undeveloped Gross Acres		Net Acres
California		15,585.58		9,092.28		4,513.64		3,511.27
All Other States		10,986.21		3,807.58		30,431.13		15,559.59
Total		26,571.79		12,899.86		34,944.77		19,070.86

Drilling Activities

The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2005, 2006 and 2007. All wells are located in the Continental U.S., in California, Texas, Louisiana and Utah.

Year	Type of Well^(a)				Gross Wells^(b)				Net Wells^(c)
			Total		Producing^(c)		Dry^(d)		Producing^(c)		Dry^(d)

2005		Exploratory		6		3		3		.7633		1.4791
		Developmental		9		6		3		1.4440		.8148

2006		Exploratory		6		3		3		.3292		1.0801
		Developmental		10		7		3		2.5921		1.3837

2007		Exploratory		4		4		0		1.8424		0
		Developmental		3		2		1		.6007		.4613

^(a) An exploratory well is one that is drilled in search of new oil and natural gas reservoirs, or to test the boundary limits of a previously discovered reservoir. A developmental well is one drilled on a previously known productive area of an oil and natural gas reservoir with the objective of completing that reservoir.

^(b) Gross wells represent the number of actual wells in which Royale Energy owns an interest. Royale Energy's interest in these wells may range from 1% to 100%.

^(c) A producing well is one that produces oil and/or natural gas that is being purchased on the market.

^(d) A dry well is a well that is not deemed capable of producing hydrocarbons in paying quantities.

^(e) One "net well" is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as a whole number or a fraction.

Production

The following table summarizes, for the periods indicated, Royale Energy's net share of oil and natural gas production, average sales price per barrel (Bbl), per thousand cubic feet (Mcf) of natural gas, and the Mcf equivalent (Mcfe) for the barrels of oil based on a 10 to 1 ratio of the price per barrel of oil to the price per Mcf of natural gas. "Net" production is production that Royale Energy owns either directly or indirectly through partnership or joint venture interests produced to its interest after deducting royalty, limited partner or other similar interests. Royale Energy generally sells its oil and natural gas at prices then prevailing on the "spot market" and does not have any material long term contracts for the sale of natural gas at a fixed price.

	2007		2006		2005
Net volume
Oil (Bbl)		14,088		21,325		16,558
Gas (Mcf)		791,195		1,074,573		1,384,860
Mcfe		932,075		1,287,823		1,550,440

Average sales price
Oil (Bbl)	$	65.02	$	60.34	$	51.95
Gas (Mcf)	$	6.56	$	6.21	$	7.48

Net production costs and taxes	$	2,116,977	$	1,968,269	$	2,751,441

Lifting costs (per Mcfe)	$	2.27	$	1.53	$	1.77

Net Proved Oil and Natural Gas Reserves

As of December 31, 2007, Royale Energy had proved developed reserves of 3,414 MMcf and total proved reserves of 3,772 MMcf of natural gas on all of the properties Royale Energy leases. For the same period, Royale Energy also had proved developed oil reserves of 24 Mbbl and total proved oil reserves of 24 Mbbl.

Oil and gas reserve estimates and the discounted present value estimates associated with the reserve estimates are based on numerous engineering, geological and operational assumptions that generally are derived from limited data.

LEGAL PROCEEDINGS

National Fuel Corporation (“NFC”) v. Royale Energy, Inc., No. 080800735, Uintah County, Utah. This lawsuit was filed on October 10, 2008, after the close of the third fiscal quarter. It arose from a dispute over jointly operated property in which Royale in the 75% owner and operator and NFC is a non-operator with a 25% ownership. NFC disagrees with the Company’s operations and seeks to remove the Company as operator. NFC also seeks unspecified damages. The case is in its very beginning, and the Company has not yet responded to the Complaint. Royale disputes the claims and intends to defend the complaint vigorously.

MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Since 1997 Royale Energy's Common Stock has been traded on the NASDAQ Global Market System under the symbol "ROYL." As of December 31, 2007, 7,918,659 shares of Royale Energy's Common Stock were held by approximately 2,990 stockholders. The following table reflects high and low quarterly closing sales prices from January 2006 through September 2008. Share prices in this table have been adjusted to give effect to the issuance of stock dividends in 2003, 2004 and 2005, and a stock split in 2004, as described in the next subsection, Dividends.

	1^st Qtr				2^nd Qtr				3^rd Qtr				4^th Qtr
	High		Low		High		Low		High		Low		High		Low
2008		3.60		2.27		14.70		2.40		12.47		3.50
2007		3.94		3.24		4.30		3.14		4.19		3.20		3.87		2.33
2006		7.23		5.55		6.93		4.95		5.66		3.86		4.92		3.50

Dividends

On January 18, 2007 the Board of Directors authorized the issuance of a cash dividend of $0.05 per share for shareholders of record on February 19, 2007. The dividend was paid March 5, 2007 in the amount of $397,049. In 2006 and 2005 we paid no cash or stock dividends. In March 2004, the board of directors declared a 28% stock split issued in the form of a stock dividend, which was distributed to stockholders on June 30, 2004. In March 2003, Royale Energy’s board of directors declared stock dividends of 3.75% payable to stockholders of record on each of the last days June, September and December 2003 and March 2004.

Recent Sales of Unregistered Securities

There were no sales of unregistered securities by Royale during the fiscal year ended December 31, 2007, or subsequently that were not previously disclosed in a quarterly report on its Form 10-Q or a current report on Form 8-K.

Performance Graph

The following stock price performance graph is included in accordance with the SEC’s executive compensation disclosure rules and is intended to allow stockholders to review Royale Energy’s executive compensation policies in light of corresponding stockholder returns, expressed in terms of the appreciation of Royale Energy’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares total return on $100 value of Royale Energy’s common stock on December 31, 2002, with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and the Dow Jones U.S. Exploration and Production Index from December 31, 2002 through December 31, 2007. The Royale Energy performance figures assume retention of stock dividends in 2003 and 2004 and a stock split issued in the form of a stock dividend in 2004.

	2002		2003		2004		2005		2006		2007
Royale Energy, Inc.		100		270		213		188		102		83
S & P Composite 500 Stock Index		100		129		143		150		173		183
DJ US Exploration and Production Index		100		131		186		307		324		465

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

The following discussion should be read in conjunction with Royale’s Financial Statements and Notes thereto and other financial information relating to Royale included elsewhere in this document.

For the past fourteen years, Royale has primarily acquired and developed producing and non-producing natural gas properties in California. In 2004, Royale began developing leases in Utah. The most significant factors affecting the results of operations are (i) changes in oil and natural gas production levels and reserves, (ii) recording of turnkey drilling revenues and the associated drilling expense, and (iii) the change in commodities price of natural gas and oil reserves owned by Royale.

Critical Accounting Policies

Revenue Recognition

Royale’s financial statements include its pro rata ownership of wells. Royale usually sells a portion of the working interest in each lease that it acquires to third party investors and retains a portion of the prospect for its own account. Royale generally retains about a 50% working interest. All results, successful or not, are included at its pro rata ownership amounts: revenue, expenses, assets, and liabilities.

Royale has developed two profit-oriented segments of business: marketing direct working interests (DWI), and producing and selling oil and gas.

Royale derives DWI revenue from sales of working interests to high net worth individuals. The DWI revenue is divided into payments for pre-drilling costs and for drilling costs. DWI investments are non-refundable. Royale recognizes the pre-drilling revenue portion when the investor deposits money with Royale. The company holds the remaining investment in trust as deferred revenue until drilling is complete. Occasionally, drilling is delayed due to the permitting process, or drilling rig availability. At December 31, 2007 and 2006, Royale had deferred drilling revenue of $3,947,097 and $5,018,261, respectively.

Royale’s primary business segment is oil and gas production. Northern and central California account for approximately 93% of the company’s successful natural gas production. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines. Monthly, price data and daily production are used to invoice customers for amounts due to Royale and other working interest owners. Royale operates virtually all of its own wells and receives industry standard operator fees.

Oil and Gas Property and Equipment

Royale follows the successful efforts method of accounting for oil and gas properties.

Costs are accumulated on a field-by-field basis. These costs include pre-drilling activities such as leasing rents paid, drilling costs, and post-drilling tangible costs. Costs of unproved properties are excluded from amortization until the properties are evaluated. Royale regularly evaluates its unproved properties on a field-by-field basis for possible impairment. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty.

Depletion

The units of production method of accounting uses proved reserves in the calculation of depletion, depreciation and amortization. Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgment determinations. Independent engineering reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and Royale considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The independent engineering estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place. Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.

Impairment Of Assets

Producing property costs are evaluated for impairment and reduced to fair value if the sum of expected undiscounted future cash flows is less than net book value pursuant to Statement of Financial Accounting Standard 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Impairment of non-producing leasehold costs and undeveloped mineral and royalty interests are assessed periodically on a property-by-property basis and any impairment in value is charged to expense. We periodically review for impairment of proved properties on a field-by-field basis. Unamortized capital costs are measured on a field basis and are reduced to fair value if it is determined that the sum of expected future net cash flows are less than the net book value. We determine if impairment has occurred through either adverse changes or as a result of its periodic review for impairment. Impairment is measured on discounted cash flows utilizing a discount rate appropriate for risks associated with the related properties or based on fair market values. We regard impairment costs of undeveloped properties as a component of our turnkey drilling overhead, since impairment costs amount to a write-down of previously acquired property inventory that we were unable to successfully develop as part of our turnkey drilling program.

Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, plant products and gas reserve volumes and the future development costs. Actual results could differ from those estimates.

Deferred Income Taxes

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Results of Operations for the Three and Nine Month Periods Ended September 30, 2008, as Compared to the Three and Nine Month Periods Ended September 30, 2007

During the third quarter ended September 30, 2008, we had a net profit of $1,373,491 compared to the net loss of $121,125 we had during the third quarter of 2007, a $1,494,616 difference. Our increase in net profit is attributed to a gain from the sale of assets. Moreover, total revenue for the third quarter of 2008 increased by $181,083 from $4,777,239 in 2007 to $4,958,322 in 2008. This increase in total revenue is the result of an increase in oil and gas production revenues. Our operating income for the quarter ended September 30, 2008 also increased to $2,128,256 from an operating loss of $138,160 for the same period in 2007, an increase of $2,266,416. The increase in operating income was also due to a gain from the sale of assets.

For the first nine months of 2008, we had a net income of $1,206,261 compared to a net loss of $1,138,485 during the first nine months of 2007, a $2,344,746 difference. This improvement was the result of increases in both of our sectors, oil and natural gas production and turnkey drilling. In addition, the increase in our net income is also attributed to a gain from the sale of assets. Total revenues for the first nine months in 2008 were $12,659,146, an increase of $1,293,850 or 11.4%, from the total revenues of $11,365,296 during the same period in 2007 due to increases oil and gas revenues and turnkey drilling revenues.

In the first nine months of 2008, revenues from oil and gas production increased $1,283,099 or 28.2% to $5,835,278 from $4,552,179 for the same period in 2007 due to higher prices received for our oil and natural gas production. The net sales volume of natural gas for the nine months ended September 30, 2008, was approximately 535,777 Mcf with an average price of $9.13 per Mcf, versus 600,579 Mcf with an average price of $6.51 per Mcf for the first nine months of 2007. This represents a decrease in net sales volume of 64,802 Mcf or 10.8%, mainly due to the natural declines in production from existing wells. For the quarter ended September 30, 2008, we produced 158,323 Mcf with an average price of $8.31 per Mcf versus 190,962 Mcf produced during the same quarter in 2007 with an average price of $5.74 per Mcf, or a 45% increase in the average price per Mcf. The net sales volume for oil and condensate (natural gas liquids) was 9,029 barrels with an average price of $104.77 per barrel for the first nine months of 2008, compared to 10,872 barrels at an average price of $58.87 per barrel for the first nine months in 2007. This represents a decrease in net sales volume of 1,843 barrels, or 16.9%. For the third quarter of 2008, oil and condensate production decreased 466 barrels, or 15.1%, from 3,090 barrels produced in 2007 to 2,623 barrels produced in the same period in 2008. This decrease was mainly due to the natural declines in production from existing wells.

Oil and natural gas lease operating expenses decreased by $108,263 or 5.5%, to $1,861,884 for the nine months ended September 30, 2008, from $1,970,147 for the same period in 2007. This decrease was mainly due to lower workover costs during the period in 2008. For the third quarter 2008, lease operating expenses increased $2,438 over the same period in 2007.

For the nine months ended September 30, 2008, turnkey drilling revenues increased $247,653 or 4.1% to $6,269,545 from $6,021,892 during the same period in 2007. We also had a $30,440 or 1% decrease in turnkey drilling and development costs to $2,926,379 in 2008 from $2,956,819 in 2007. In the third quarter of 2008, turnkey drilling revenues decreased $190,352, or 5.9%, while turnkey drilling and development costs increased by $328,262, or 21.6%, over the same quarter in 2007. Turnkey drilling revenues decreased in the third quarter due to lower turnkey revenues from the wells drilled during the period in 2008 compared to the wells drilled during the same period in 2007. Turnkey drilling costs increased because we drilled and completed three wells during the third quarter of 2008, while in the same period in 2007 two wells were drilled. We expect drilling activity to increase during the fourth quarter of 2008. Prior to September 30, we began drilling one well in Utah and in mid October started drilling another well in California. We also processed the permits on three additional wells in California and one in Utah. In total, we expect to drill approximately four wells during the fourth quarter of 2008.

We periodically review our proved properties for impairment on a field-by-field basis and charge impairments of value to the expense. Impairment losses of $820,966 and $34,894 were recorded in the first nine months of 2008 and 2007, respectively. These impairments were mainly due to various lease and land costs that were no longer viable.

In September 2008, the company sold its Rio Bravo field located in Kern County, California for $4.75 million, resulting in a net gain from the sale of $2,637,203. During the first quarter in 2008, we also recorded a loss of $27,823 on the sale of a non-oil and gas asset.

The aggregate of supervisory fees and other income was $554,323 for the nine months ended September 30, 2008, a decrease of $236,902 (29.9%) from $791,225 during the same period in 2007. Third quarter supervisory fees and other income decreased $75,503, or 27.8%, to $196,310 from $271,813 in 2007. These decreases were due to lower interest income received on our available cash and lower cost recovery fees on facilities as the result of lower natural gas production.

Depreciation, depletion and amortization expense decreased to $2,601,622 from $2,905,024, a decrease of $303,402 (10.4%) for the nine months ended September 30, 2008, as compared to the same period in 2007. This decrease in depletion expense was mainly due to the decrease in our oil and gas assets from our 2007 impairments.

General and administrative expenses decreased by $304,151 or 9.1%, from $3,345,386 for the nine months ended September 30, 2007, to $3,041,235 for the period in 2008. Third quarter 2008 general and administrative expense decreased $52,760, or 4.9% from $1,069,442 in 2007 compared to $1,016,682 in 2008. These decreases were primarily due lower employee related travel and insurance costs due to our cost control measures.

Marketing expense for the three quarters ended September 30, 2008, decreased $164,006, or 15.2%, to $916,625, compared to $1,080,631 for the same period in 2007. For the third quarter, marketing expenses increased $54,171, or 16.8%, to $377,605 from $323,434 for the same period in 2007. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

Legal and accounting expense increased to $1,067,197 for the nine months of 2008, compared to $629,480 for same period in 2007, a $437,717 or 69.5% increase. For the third quarter, legal and accounting expenses decreased by $283,663, or 82.2% from the same period last year. The increase in legal and accounting expense for the first nine months of 2008 stems from higher legal fees relating to a litigation defending property rights during the period, which culminated in a trial and a successful outcome for the company in April.

Interest expense increased to $195,408 for the three quarters ended September 30, 2008, from $116,435 for the same period in 2007, a $78,973, or 67.8% increase. This was due to an increase in the usage of our bank line of credit. For the nine months ended September 30, 2008, income tax expense increased $1,204,112 from a benefit of $579,966 in 2007 to an expense of $624,146 in 2008. The change is the result of the company operating from a net operating loss in 2007 to a net operating profit in 2008.

Results of Operations for the Twelve Months Ended December 31, 2007, as Compared to the Twelve Months Ended December 31, 2006

For the year ended December 31, 2007, we had a net loss of $2,779,207 compared to the net loss of $2,649,701 achieved during 2006. A major component of the loss was an impairment of $2,106,670 due to a decrease in reserve values at year end 2007. The loss also resulted from decreases in revenues from both the turnkey drilling and the oil and natural gas production segments of our business.

Total revenues from operations for the year in 2007 were $16,557,399, a decrease of $8,338,644, or 33.5%, from the total revenues of $24,896,043 in 2006. In 2007 our natural gas revenues decreased due to lower natural gas and oil production and our turnkey drilling revenues declined due to a decrease in the number of wells drilled. Lower oil and natural gas production accounted for 22% of the decrease, and lower turnkey drilling revenues accounted for 76% of the decrease.

In 2007, revenues from oil and gas production decreased by 23.3% to $6,110,092 from $7,965,633 in 2006, due to a decrease in natural gas and oil production. The net sales volume of natural gas for the year ended December 31, 2007, was approximately 791,195 Mcf with an average price of $6.56 per Mcf, versus 1,074,573 Mcf with an average price of $6.21 per Mcf for 2006. This represents a decrease in net sales volume of 283,378 Mcf or 26.4%. This decrease in production was due to a natural decline in production from existing oil and gas wells and to the sale of a number of underperforming properties at the end of 2006. The net sales volume for oil and condensate (natural gas liquids) production was approximately 14,088 barrels with an average price of $65.02 per barrel for the year ended December 31, 2007, compared to 21,325 barrels at an average price of $60.34 per barrel for the year in 2006. This represents a decrease in net sales volume of 7,237 barrels, or 33.9%.

Oil and gas lease operating expenses increased by $148,708, or 7.6%, to $2,116,977 for the year ended December 31, 2007, from $1,968,269 for the year in 2006. This increase was mainly due to higher workover costs during the period in 2007 when compared to 2006, as we attempted to increase production on some of our existing wells. When measuring lease operating costs on a production or lifting cost basis, in 2007, the $2,116,977 equates to a $2.27 per mcfe lifting cost versus a $1.53 per mcfe lifting cost in 2006, a 48.4% increase.

For the year ended December 31, 2007, turnkey drilling revenues decreased $6,303,447 to $9,408,103 in 2007 from $15,711,550 in 2006, or 40.1%. We also had a $4,650,583 or 48.3% decrease in turnkey drilling and development costs to $4,977,811 in 2007 from $9,628,394 in 2006. These decreases were mainly due to fewer wells drilled, seven during the year in 2007 while sixteen wells were drilled during the year in 2006, as we focused our efforts into developing the Utah property. We drilled four exploratory wells and three developmental wells in 2007 versus six exploratory wells and ten developmental wells in 2006. Exploratory wells tend to be more expensive due to new lease, geological and geophysical and facility costs. Our gross margins, or profits, on drilling depend on our ability to accurately estimate the costs associated with the development of projects in which we sell working interests and to acquire viable properties that can be successfully developed. Costs associated with contract drilling depend on location, well depth, weather, and availability of drilling contractors and equipment. Our gross margin on drilling was 47.1% and 38.7% for the years ended December 31, 2007 and 2006, respectively. Gross margin is calculated as the difference between turnkey drilling revenue and turnkey drilling expense. However, management believes that a portion of its impairment losses should also be considered as a cost of drilling in determining the profitability of this segment, because impairment costs are incurred in the selection of higher quality prospects for ultimate development.

Impairment losses of $2,106,670 and $6,191,417 were recorded in 2007 and 2006, respectively. In 2007 and 2006, we recorded impairments in fields where year end reserve values no longer supported the net book values of wells in those fields. In 2007, the majority of this impairment, $1,248,843, was recorded in our Bowerbank field in California, where various recently drilled wells had significantly lower proved undeveloped reserves than originally estimated. The Afton field in California was impaired for $389,946 mainly on acquired wells which ceased producing due to their natural declines and had lower reserves than originally estimated. Our Texas and Gulf Coast fields were impaired $283,371 due to wells in these areas which had lower production and reserves than originally estimated. Our Elkhorn Slough field was impaired for $148,734 due to lower proved undeveloped reserves than originally estimated. In 2006, the primary focus of this impairment, $4,068,843, was recorded for our wells in the Texas and Gulf Coast fields. There were several wells in this area that had been drilled in the last few years which had significantly lower production and reserves than originally estimated. The Bowerbank field in California was impaired for $1,331,093 mainly for older wells which ceased producing due to their natural declines. Our Cache Creek field was impaired for its remaining value of $399,269 due to the drilling of the North Crossroads 6-34 which proved unsuccessful. The Willows field was also impaired for $255,109 due to the drilling of the North Willows 3 which although successful had lower reserves than originally estimated.

We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges where doubtful. The Company does not attempt collection from its Direct Working Interest owners for certain wells that ceased production or had been sold during the year, to the extent that these charges exceed production revenue. As a result of that review in 2007 and 2006, we established an allowance of $546,874 and $567,000, respectively, for receivables from these Direct Working Interest owners.

The aggregate of supervisory fees and other income was $1,039,204 for the year ended December 31, 2007, a decrease of $179,656 (14.7%) from $1,218,860 during the year in 2006. This decrease was the result of several factors including the decrease in the number of wells operated due to the sale of properties in 2006, the decrease in drilling and the decrease in cost recovery received for use of facilities constructed and placed into service during prior periods as a result of lower production levels. Supervisory fees are charged in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for reimbursement of expenses associated with the joint accounting for billing, revenue disbursement, and payment of taxes and royalties. These charges are reevaluated each year and adjusted up or down as deemed appropriate by a published report to the industry by Ernst & Young, LLP, Public Accountants. Supervisory fees decreased $83,718 or 17.3%, to $400,897 in 2007 from $484,615 in 2006.

Depreciation, depletion and amortization expense decreased to $3,585,682 from $5,833,904 a decrease of $2,248,222 (38.5%) for the year ended December 31, 2007, as compared to 2006. The depletion rate is calculated using production as a percentage of reserves. This decrease in depletion expense was mainly due to the decrease in our oil and gas assets from our 2006 asset sale and impairments.

We also reevaluated our inventory of capitalized geological lease and land costs, in order to write off those prospects that may be no longer viable. As a result, $423,459 of previously capitalized costs were written off and recorded as geological and geophysical expense during 2007, compared with $400,306 written off in 2006, a $23,153 or 5.8% increase. This expense is directly attributable to the selection and prioritization of the quality of the company’s drilling prospects.

General and administrative expenses decreased by $416,450 or 8.1%, from $5,129,074 for the year ended December 31, 2006 to $4,712,624 for the year in 2007. This decrease was primarily due to a bad debts write-off in 2006 of approximately $582,204, compared to $262,532 in 2007, for receivables from direct working interest investors whose expenses on non-producing wells are contractually not collectable. Legal and accounting expense increased to $928,628 for the year, compared to $397,575 for year 2006, a $531,053 or 133.6% increase. This increase was due to higher legal fees due to litigation defending property rights during 2007.

Marketing expense for the year ended December 31, 2007 decreased $343,792 or 19.1%, to $1,455,296, compared to $1,799,088 for the year in 2006. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

During 2007 we sold our interests in two non oil and gas assets resulting in a loss on sale of $135,396. In November 2006 we sold 19 of our producing Sacramento Basin wells and support facilities for $4,510,000, resulting in a gain on sale of $3,263,368.

During 2007 interest expense decreased to $152,547 from $523,139 in 2006, a $370,592 or 70.8% decrease. This decrease was due to principal balance reduction on our line of credit and to the decrease in the interest rate charged to the company, which went from 8.75% at December 31, 2006, to 7.75% at December 31, 2007.

In 2007 we had an income tax benefit of $1,258,484 mainly due to our net loss before taxes of $4,037,691. In 2006 we also had an income tax benefit of $1,062,054 also due to our net loss before taxes of $3,711,755 and the utilization of our depletion carryforwards. The use of percentage depletion created from the current operations, and from utilization of unused percentage depletion carryforwards, results in an effective tax rate less than the normal federal rate of 35% plus the relevant state rates (mostly California, 9.3%).

Results of Operations for the Twelve Months Ended December 31, 2006, as Compared to the Twelve Months Ended December 31, 2005

For the year ended December 31, 2006, we had a net loss of $2,649,701, a $3,835,604 decrease compared to the net profit of $1,185,903 achieved during 2005. The largest single component of the loss was a result of an impairment of $6,191,417 which we realized due to the decrease in reserve values at year end 2006. These decreased reserve values also caused our depletion rate to increase which led to a higher depletion expense.

Total revenues from operations for the year in 2006 were $24,896,043, a decrease of $747,335 or 2.9%, from the total revenues of $25,643,378 in 2005. In 2006 our natural gas revenues decreased due to lower natural gas production and prices, but this decrease was largely offset by increased turnkey drilling revenues. In addition to operating revenue, we realized a one time gain of $3.3 million from the sale of a number of wells in the Sacramento Basin. We sold these properties to reduce overall cost of operation and realign cash toward higher potential drilling opportunities.

In 2006, revenues from oil and gas production decreased by 29.1% to $7,965,633 from $11,228,537 in 2005, due to a decrease in natural gas production. The net sales volume of natural gas for the year ended December 31, 2006, was approximately 1,074,573 Mcf with an average price of $6.21 per Mcf, versus 1,384,860 Mcf with an average price of $7.48 per Mcf for 2005. This represents a decrease in net sales volume of 310,287 Mcf or 22.4%. This decline in production was the result of several factors. These include a natural decline of production from our existing oil and gas wells and delays in bringing new production on line due to limited drilling rig availability in California. This limited rig availability delayed our being able to start new drilling and proceed with necessary workovers on existing wells. The net sales volume for oil and condensate (natural gas liquids) production was 21,325 barrels with an average price of $60.34 per barrel for the year ended December 31, 2006, compared to 16,558 barrels at an average price of $51.95 per barrel for the year in 2005. This represents an increase in net sales volume of 4,767 barrels, or 28.8%.

Oil and gas lease operating expenses decreased by $783,172, or 28.5%, to $1,968,269 for the year ended December 31, 2006, from $2,751,441 for the year in 2005. The decrease was due to increased efficiency and a reduction in workover activity and associated costs in 2006 compared to 2005. When measuring lease operating costs on a production or lifting cost basis, in 2006, the $1,968,269 equates to a $1.53 per mcfe lifting cost versus a $1.77 per mcfe lifting cost in 2005, a 13.6% decrease.

For the year ended December 31, 2006, turnkey drilling revenues increased $2,644,750 to $15,711,550 in 2006 from $13,066,800 in 2005, or 20.2%. We also had a $1,517,146 or 18.7% increase in turnkey drilling and development costs to $9,628,394 in 2006 from $8,111,248 in 2005. The higher turnkey drilling revenues and drilling and development costs were mainly due to increases in both direct working interest sales and in the number and cost of wells drilled during 2006 when compared to 2005. We drilled six exploratory wells and ten developmental wells in 2006 versus six exploratory wells and nine developmental wells in 2005. Exploratory wells tend to be more expensive due to new lease, geological and geophysical and facility costs. Our gross margins, or profits, on drilling depend on our ability to accurately estimate the costs associated with the development of projects in which we sell working interests and to acquire viable properties that can be successfully developed. Costs associated with contract drilling depend on location, well depth, weather, and availability of drilling contractors and equipment. Our gross margin on drilling was 38.7% and 37.9% for the years ended December 31, 2006 and 2005, respectively. Gross margin is calculated as the difference between turnkey drilling revenue and turnkey drilling expense. However, management believes that a portion of its impairment losses should also be considered as a cost of drilling in determining the profitability of this segment, because impairment costs are incurred in the selection of higher quality prospects for ultimate development.

Impairment losses of $6,191,417 and $742,642 were recorded in 2006 and 2005, respectively. In 2006, we recorded impairments in fields where year end reserve values no longer supported the net book values of wells in those fields. The primary focus of this impairment, $4,068,843 was recorded for our wells in the Texas and Gulf Coast fields. There were several wells in this area that had been drilled in the last few years which had significantly lower production and reserves than originally estimated. The company holds a non-operated interest in this property, and had been unable to influence operational decisions to set lower risk objectives. As a result, the company will seek other strategic partners to assist in the future development of this property. The Bowerbank field in California was impaired for $1,331,093 mainly for older wells which ceased producing due to their natural declines. Our Cache Creek field was impaired for its remaining value of $399,269 due to the drilling of the North Crossroads 6-34 which proved unsuccessful. The Willows field was also impaired for $255,109 due to the drilling of the North Willows 3 which although successful had lower reserves than originally estimated.

In 2005, we recorded an impairment in our Afton field due to drilling exploratory wells which were not successful. We also recorded an impairment in the Cache Creek field as a result of the, North Crossroads 1 and North Crossroads 4, watering out and ceasing production in 2005.

We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges where doubtful. The Company does not attempt collection from its Direct Working Interest owners for certain wells that ceased production or had been sold during the year, to the extent that these charges exceed production revenue. As a result of that review in 2006 and 2005, we established an allowance of $567,000 and $401,691, respectively, for receivables from these Direct Working Interest owners.

The aggregate of supervisory fees and other income was $1,218,860 for the year ended December 31, 2006, a decrease of $129,181 (9.6%) from $1,348,041 during the year in 2005. This was due to a decrease in cost recovery received for use of facilities constructed and placed into service during prior periods as a result of lower production levels. Supervisory fees are charged in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for reimbursement of expenses associated with the joint accounting for billing, revenue disbursement, and payment of taxes and royalties. These charges are reevaluated each year and adjusted up or down as deemed appropriate by a published report to the industry by Ernst & Young, LLP, Public Accountants. Supervisory fees decreased $8,800 or 1.8%, to $484,615 in 2006 from $493,415 in 2005.

Depreciation, depletion and amortization expense increased to $5,833,904 from $4,062,587 an increase of $1,771,317 (43.6%) for the year ended December 31, 2006, as compared to the same period in 2005. The depletion rate is calculated using production as a percentage of reserves. This increase in depreciation expense was mainly due to a higher depletion rate because of lower reserves at the end of 2006.

We also reevaluated our inventory of capitalized geological lease and land costs, in order to write off those prospects that may be no longer viable. As a result, $400,306 of previously capitalized costs were written off and recorded as geological and geophysical expense during 2006, compared with $381,790 written off in 2005, an $18,516 or 4.9% increase. This expense is directly attributable to the selection and prioritization of the quality of the company’s drilling prospects.

General and administrative expenses increased by $251,906 or 5.2%, from $4,877,168 for the year ended December 31, 2005 to $5,129,074 for the year in 2006. This increase was mainly due to the increase in bad debts expense of $180,513, from $401,691 in 2005 to $582,204 in 2006, for receivables from direct working interest investors whose expenses on non-producing wells was unlikely to be collected. Employee related travel and lodging costs also increased by $85,636. Legal and accounting expense increased to $397,575 for the year, compared to $236,199 for year 2005, a $161,376 or 68.3% increase. This increase was due to higher legal fees due to litigation defending property rights during 2006.

Marketing expense for the year ended December 31, 2006 decreased $423,771 or 19.1%, to $1,799,088, compared to $2,222,859 for the year in 2005. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

During the year 2006, interest expense increased to $523,139 from $444,271 in 2005, a $78,868 or 17.8% increase. This was due to an increase in the interest rate charged to the company, which went from 7.75% at December 31, 2005, to 8.75% at December 31, 2006.

In 2006 we had an income tax benefit of $1,062,054 mainly due to our net loss before taxes of $3,711,755 and the utilization of our depletion carryforwards. In 2005 our income tax expense was $627,270 due to our net income before taxes of $1,813,173. For the period in 2005, this represents an effective tax rate of approximately 34.6%, respectively. The use of percentage depletion created from the current operations, and from utilization of unused percentage depletion carryforwards, results in an effective tax rate less than the normal federal rate of 35% plus the relevant state rates (mostly California, 9.3%).

Capital Resources and Liquidity

At December 31, 2007, Royale had current assets totaling $9,174,687 and current liabilities totaling $14,021,131, a $4,846,444 working capital deficit. At September 30, 2008, Royale had current assets totaling $13,015,612 and current liabilities totaling $13,154,160, for a $138,548 working capital deficit. We had cash and cash equivalents at September 30, 2008 of $6,663,717 compared to $3,848,968 at December 31, 2007 and $7,377,604 at December 31, 2006. During the nine months ended September 30, 2008, we repaid $2,600,000 on our commercial bank credit line and loan.

Our capital expenditure commitments occur as we decide to drill wells to develop our prospects. We generally do not decide to drill any prospect until we have sold a portion of the working interest in a prospect to third parties to diversify our risk and receive a portion of the funds to drill each prospect. We place funds that we receive from third party investors into a separate cash account until they are required for expenditures on each well. Our capital expenditure needs in addition to those needs are satisfied by selling part of the working interest in prospects.

We have not, in past years, experienced shortages of funds needed to satisfy our capital expenditure requirements. We expect that our available credit and cash flows from operations will be sufficient for capital expenditure needs beyond those satisfied from sales of working interests.

We ordinarily fund our operations and cash needs from cash flows generated from operations. During the fourth quarter of each year, we receive a large percentage of the revenue generated by our sales of working interests to third parties, as individual high net worth investors make investments according to their own year-end financial planning. We also incur a large percentage of our costs for drilling activities in the third and fourth quarters of each year. We believe that we have sufficient liquidity for 2007 and do not foresee any liquidity demands that cannot be met from cash flow from operations.

At the end of 2007, our accounts receivable totaled $4,090,341 compared to $2,906,290 at December 31, 2006, a $1,184,051 or 40.7% increase, primarily due to receivables from industry members participating in wells we drilled at the end of 2007. At September 30, 2008, our accounts receivable totaled $4,542,624. At December 31, 2007, our accounts payable and accrued expenses totaled $10,080,034, an increase of $2,921,422 or 40.8% over the accounts payable at the end of 2006 of $7,158,612. This increase was primarily due to drilling and completion of two Utah wells, and the workover of a California well at year end in 2007.

Occasionally we borrow from banks, using our oil and gas properties as security. In 2007, we drew approximately $1,132,929 net, in order to meet our drilling schedule. In 2006, we made net principal repayments of approximately $2,590,000 on our credit line, mainly due to the oil and gas asset sale at the end of the year.

We have a revolving line of credit under a loan agreement with Guaranty Bank, FSB, which is secured by all of our oil and gas properties. At September 30, 2008, we had outstanding indebtedness on this loan of $2,575,974. At December 31, 2007, we had outstanding indebtedness of $5,175,974. Unused available credit from this revolving line of credit totaled approximately $200,000 at December 31, 2007. At December 31, 2006, we had outstanding indebtedness of $3,810,000 with unused available credit of approximately $10,974. The loan agreement also contains certain restrictive covenants, including the prohibition of payment of dividends on our stock (other than dividends paid in stock). The loan agreement contained covenants that, among other things, we must:

Maintain a minimum ratio of earnings before interest, taxes, depreciation and amortization to debt service requirements of at least 1.25 to 1.00;

Maintain a ratio of bank determined current assets to bank determined current liabilities of at least 1.00 to 1.00; and

Maintain a tangible net worth as of the close of each fiscal quarter of at least $8,188,000 as of September 30, 2002, plus 50% of positive quarterly net income thereafter.

On the date of this prospectus, Royale was in compliance with its loan covenants.

During 2004 we obtained a new loan from Guaranty Bank, FSB for $1,000,000, which was secured by our non-oil and gas real estate assets, which was primarily used to fund operations. In 2005, portion of the real estate was subsequently sold during the year resulting in an additional $175,000 principal payment. At December 31, 2006, we had outstanding indebtedness of $233,045 on this loan. The principal balance of this loan was repaid in March 2007.

We do not engage in hedging activities or use derivative instruments to manage market risks.

The following schedule summarizes our known contractual cash obligations at December 31, 2007, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.

	Total Obligations		2008		2009-2010		2011-2012		Beyond
Office lease	$	2,915,872	$	348,689	$	728,412	$	772,157	$	1,066,614
Long-term debt		5,175,974		-		5,175,974		-		-
Total	$	8,091,846	$	348,689	$	5,904,386	$	772,157	$	1,066,614

Operating Activities. For the year ended December 31, 2007, cash provided by operating activities totaled $4,427,012 compared to $3,406,393 provided by operating activities for the same period in 2006, a $1,020,619 or 30% increase, mainly due to our increase in accounts payable and accrued expenses from drilling. Cash provided by operating activities for 2006 decreased $2,989,049 or 46.7% as compared to $6,395,442 for the year ended December 31, 2005 mainly due to our net loss from operations.

For the three quarters ended September 30, 2008, cash provided by operating activities totaled $1,001,852 compared to $4,304,038 for the same period in 2007, a $3,302,186 or 76.7% decrease. This decrease in cash provided was due to a decrease in our accounts payable and accrued expenses.

Investing Activities. Net cash used by investing activities netted to $8,691,528 for the year in 2007, which included $8,835,180, used mainly for oil and gas capital expenditures, along with proceeds from our non oil and gas assets sale of $143,652. In 2006, net cash provided by investing netted to $1,932,738 which included $3,091,316 used for oil and gas and other capital expenditures along with proceeds from our oil and gas asset sales of $5,024,054. Net cash used by investing activities in 2005 were $9,888,809 due mainly to normal oil and gas capital expenditures.

Net cash provided by investing activities amounted to $582,898 for the first nine months of 2008, compared to $5,074,132 used by investing activities for the same period in 2007, a difference of $5,657,030 in cash used. This difference is the result of $4,885,212 in drilling expenditures for the nine months ended September 30, 2008 offset by proceeds from the sale of assets. Beginning in July 2008, the company began to purchase Aspen common stock. For the three months ended September 30, 2008, we have purchased $250,440 and sold $19,641 in Aspen stock.

Financing Activities. For the year ended December 31, 2007 cash provided by financing activities was $735,880 compared to $2,678,299 used by financing activities in 2006. This difference was primarily due to an increase in net borrowings on our commercial bank line of credit during the period in 2007. Also, in January 2007, the Board of Directors declared a cash dividend of $0.05 per share for shareholders of record on February 19, 2007. This dividend was paid March 5, 2007, in the amount of $397,049. In 2005, cash provided by financing activities was $583,094. The difference in cash between 2006 and 2005 was primarily due to net principal loan repayments during 2006 due to the asset sale.

For the nine months ended September 30, 2008, cash provided by financing activities was $1,229,999 compared to $2,715,094 used by financing activities for the same period in 2007, a $3,945,093 difference. In the second quarter of 2008 we received net proceeds of $3,724,999 from the sale of common stock and warrants to one investor in a private placement. The proceeds were used to pay $2,000,000 to reduce long term debt payments and for working capital. We also received $105,000 from the exercise of stock options.

Changes in Reserve Estimates

In 2007, our estimated proved developed and undeveloped reserve quantities were revised downward by approximately 4.05 million cubic feet of natural gas. See, Supplemental Information about Oil and Gas Producing Activities (Unaudited). During 2007, it was discovered that two producing wells had lower than previously estimated proved producing gas reserves, resulting in a reduction of proved developed producing gas reserves. There were also reductions on two additional producing wells that had lower than previously estimated proved non-producing reserves. Also during 2007, four prospects that had been previously estimated to contain proved undeveloped gas reserve were re-evaluated and found to have lower than expected reserves and as a result were not drilled. Three other prospects that had been previously estimated to contain proved undeveloped gas reserve are still being evaluated and pending final results expected reserves were reduced. One other prospect with proved undeveloped reserves were drilled and resulted in proved reserves less than prior estimates. The revisions of previous estimates attributable to these wells accounted for approximately 98% of the net downward revisions of previous gas reserve estimates.

The following table summarizes the major reasons for reserve reductions in 2007.

	Gas
Two existing wells with lower estimated proved producing reserves		(385,846	)
Two existing wells with lower estimated proved non-producing reserves		(494,000	)
Reduction of PUD due to four undrilled wells		(1,716,000	)
Reduction of PUD due to three undrilled wells pending evaluation		(1,166,000	)
Reduction of PUD based on drilling results		(218,368	)
Total		(3,980,214	)

In 2006, our estimated proved developed and undeveloped reserve quantities were revised downward by approximately 1.02 million cubic feet of natural gas and 34,000 barrels of oil. See, Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-30. During 2006, it was discovered that four producing wells had lower than previously estimated non-producing gas reserves, resulting in a reduction of proved developed non-producing gas reserves. Also during 2006, two prospects that had been previously estimated to contain proved undeveloped gas reserve were re-evaluated and found to have lower than expected reserves and as a result were not drilled. One other prospect with proved undeveloped reserves was drilled and resulted in proved reserves less than prior estimates. The revisions of previous estimates attributable to these wells accounted for approximately 99% of the net downward revisions of previous gas reserve estimates.

The reduction in oil reserve estimates in 2006 was due to a re-evaluation of two prospects that had been previously estimated to contain proved undeveloped oil reserves were found to have lower than expected reserves and as a result were not drilled. Also, one prospect with proved undeveloped oil reserves was drilled and resulted in proved oil reserves less than prior estimates. The revisions of previous estimates attributable to these wells accounted for approximately 74% of the net downward revisions of previous gas reserve estimates.

The following table summarizes the major reasons for reserve reductions in 2006.

	Oil			Gas
Four existing wells with lower estimated proved non-producing reserves					(575,877	)
Reduction of PUD due to two undrilled wells		(16,000	)		(212,000	)
Reduction of PUD based on drilling results		(9,000	)		(231,045	)
Total		(25,000	)		(1,018,922	)

In 2005, our estimated proved developed and undeveloped reserve quantities were revised downward by approximately 2.1 million cubic feet of natural gas 200,000 barrels of oil. See, Supplemental Information about Oil and Gas Producing Activities (Unaudited).

During 2005, three producing wells ceased producing, resulting in a reduction in proved developed reserves. Also during 2005, one prospect that had been previously estimated to contain proved undeveloped gas reserve was drilled and resulted in a dry hole, and two other prospects with proved undeveloped reserves were drilled and resulted in proved reserves less than prior estimates. The revisions of previous estimates attributable to these wells accounted for approximately 93% of the net downward revisions of previous gas reserve estimates.

The reduction in oil reserve estimates in 2005 was mainly due to re-evaluation of one oil/condensate well, which was drilled at the end of 2004 and began production in 2005. Based on its production experience, oil reserves for that well were reduced by 161,409 barrels, which equals 80% of net oil reserve reductions in 2005.

The following table summarizes the major reasons for reserve reductions in 2005.

	Oil			Gas
Two existing wells which ceased production					(738,212	)
Reduction of PUD due to one dry hole					(461,000	)
Reduction of PUD based on drilling results		(161,409	)		(781,293	)
Total		(161,409	)		(1,980,505	)

ROYALE’S QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our major market risk exposure relates to pricing of oil and gas production and in interest rates. The prices we receive for oil and gas are closely related to worldwide market prices for crude oil and local spot prices paid for natural gas production. Prices have been volatile for the last few years, and we expect that volatility to continue. In 2007, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline. In 2007, our natural gas revenues were approximately $5.2 million with an average price of $6.56 per MCF.Monthly average natural gas prices ranged from a low of $6.74 per Mcf to a high of $12.02 per Mcf for the first nine months of 2008. During the first three weeks of October, we observed the price of oil and natural gas decrease, which may reduce our oil and gas production revenue in the next quarter especially if new production brought online during the fourth quarter does not exceed the natural declines in production from out existing wells. We have not entered into any hedging or derivative agreements to limit our exposure to changes in oil and gas prices or interest rates.

DIRECTORS AND EXECUTIVE OFFICERS OF ROYALE

Name	Age	First Became Director or Executive Officer	Positions Held

Harry E. Hosmer	77	1986	Chairman of the Board
Donald H. Hosmer	54	1987	President and Director
Stephen M. Hosmer	41	1996	Executive Vice President, Chief Financial Officer and Director
Oscar Hildebrandt ^{(1) (2)}	72	1995	Secretary and Director
George M. Watters ^{(1) (2)}	88	1991	Director
Gilbert C. L. Kemp⁽¹⁾	74	1998	Director
Gary Grinsfelder	58	2007	Director
Tony Hall⁽²⁾	66	2007	Director

⁽¹⁾ Member of the audit committee.

⁽²⁾ Member of the compensation committee.

The board has determined that directors Gary Grinsfelder, Tony Hall, Oscar Hildebrandt, George M. Watters and Gilbert C. L. Kemp qualify as independent directors under NASDAQ rules.

Harry E. Hosmer– Chairman of the Board

Harry E. Hosmer has served as chairman since Royale Energy began in 1986, and from inception in 1986 until June 1995, he also served as president and chief executive officer.

Donald H. Hosmer - President, Chief Executive Officer, Secretary and Director

Donald H. Hosmer has served as an executive officer and director of Royale Energy since its inception in 1986, and in June 1995 he became president and chief executive officer. Prior to becoming president, he was executive vice president, responsible for marketing working interests in oil and gas projects developed by Royale Energy. He was also responsible for investor relations and communications. Donald H. Hosmer is the son of Harry E. Hosmer and brother of Stephen M. Hosmer.

Stephen M. Hosmer– Executive Vice President, Chief Financial Officer, Director

Stephen M. Hosmer joined Royale Energy as the management information systems manager in May 1988, responsible for developing and maintaining Royale Energy’s computer software. Mr. Hosmer developed programs and software systems used by Royale Energy. From 1991 to 1995, he served as president of Royale Operating Company, Royale Energy’s operating subsidiary. In 1995, he became chief financial officer of Royale Energy. In 1996, he was elected to the board of directors of Royale Energy. In 2003, he was elected executive vice president. Mr. Hosmer served seven years on the board of directors of Youth for Christ, a charitable organization in San Diego, California. Stephen M. Hosmer is the son of Harry E. Hosmer and brother of Donald H. Hosmer. Mr. Hosmer holds a Bachelor of Science degree in Business Administration from Oral Roberts University in Tulsa, Oklahoma, as well as earning his MBA degree via the prestigious President/Key Executive program at Pepperdine University in Malibu, California.

Oscar Hildebrandt, D.V.M. - Director

Dr. Hildebrandt served as an advisory member of Royale Energy’s board of directors from 1994 to 1995 and became a director in 1995. He serves as chairman of Royale Energy’s audit committee. Dr. Hildebrandt practiced veterinary medicine as President of Medford Veterinary Clinic, Medford, Wisconsin, from 1960 to 1990. Since 1990, Dr. Hildebrandt has engaged independently in veterinary practice consulting services. He has served on the board of directors of Fidelity National Bank - Medford, Wisconsin, and its predecessor bank from 1965 to the present and is past chairman of the board of the Bank. From 1990 to the present he has acted as a financial advisor engaged in private business interests. Dr. Hildebrandt received a Bachelor of Science degree from the University of Wisconsin in 1954 and a Doctor of Veterinary Medicine degree from the University of Minnesota in 1958.

Gilbert C.L. Kemp– Director

Mr. Kemp has since 2002 served as an independent consultant for seismic operations in the oil and gas industry. He managed the California operations of Western Atlas, Inc., a New York Stock Exchange company from 1998 until 2002. Mr. Kemp was a founding member of 3-D Geophysical, Inc., where he served as Vice President from 1996 until March 1998. In March 1998 3-D Geophysical, whose stock had been listed on the Nasdaq National Market System since February 1996, merged with Western Atlas, Inc. During the years 1987 to 1995, Mr. Kemp served as president and CEO of Kemp Geophysical Corporation, which owned and operated seismic crews in the United States and Canada.

Gary Grinsfelder– Director

Mr. Grinsfelder is a qualified manager and geologist with 33 years experience in oil and gas exploration, exploitation and property evaluation. He is Executive Vice President – Exploration and Business Development, and Secretary of Output Exploration, LLC, Houston, Texas, where he has been employed since 1994. He has also served in geologic and management roles for Araxas Exploration, Inc., Triad Energy Corporation, Spartan Petroleum Corporation, American Petrofina Company of Texas, Union Oil Company of California and Degolyer and MacNaughton. He received a Bachelor of Science degree in 1972 from Southern Methodist University and has performed graduate studies at the University of Puerto Rico Department of Marine Science and University of Houston Department of Geology.

Tony Hall – Director

Ambassador Hall served as a member of the United States House of Representatives, representing the people of the Third District of Ohio, for almost twenty-four years, from 1979 to 2002. In 2002 he was appointed U.S. Ambassador to the United Nations Agencies for Food and Agriculture. He served as chief of the U.S. Mission to the U.N. Agencies in Rome – the Work Food Program, Food and Agriculture Organization and International Fund for Agricultural Development. He has been nominated for the Nobel Peace Prize on three occasions for his humanitarian and hunger-related work. He received his A. B. degree from Denison University, Granville, Ohio, in 1964.

George M. Watters – Director

Mr. Watters has been a Director of Royale Energy, Inc. since 1991. He has many years of senior management experience, including 23 years with Amoco, in all phases of downstream petroleum operations - marketing, refining, trading and commercial development. As CEO, he was instrumental in the conception and development of two successful grass roots refining and marketing projects in Australia and Singapore. His last assignment was Chief Executive of Amoco Shipping and Trading Company, residing in London. Prior to his affiliation with Amoco, he held various senior management positions with the former Standard-Vacuum Oil Company, jointly owned by Exxon and Mobil. He is a graduate of MIT and also attended their Management Program for Senior Executives. During World War II, Mr. Watters served four years as an officer in the U.S. Navy Civil Engineering Corps.

ROYALE EXECUTIVE COMPENSATION

The following table summarizes the compensation of the chief executive officer, chief financial officer and the two other most highly non-executive employees (the “named executives and employees”) of Royale Energy and its subsidiaries during 2007.

Name and Principal Position	Year		Salary		Bonus		All Other Compensation (1)		Total
			($)		($)		($)		($)
Donald Hosmer		2007	$	225,077			$	6,752	$	231,829
President		2006	$	212,234			$	20,515	$	232,749
		2005	$	204,615			$	6,138	$	210,753

Stephen Hosmer		2007	$	213,823			$	18,775	$	232,598
Exec. V.P. & CFO		2006	$	203,397			$	20,517	$	223,914
		2005	$	194,385			$	5,832	$	200,217

William Donaldson (2)		2007	$	173,769	$	20,000	$	5,213	$	198,982
Chief Engineer		2006	$	41,253					$	41,253

Mohamed Abdel-Rahmen		2007	$	150,386			$	4,250	$	154,636
VP Exploration

(1) All other compensation consists of matching contributions to the Company’s simple IRA plan, except for Stephen M. Hosmer, who also received a $20,000 car allowance.

(2) Mr. Donaldson and Mr. Abdel-Rahmen are highly compensated employees under SEC rules who did not serve as executive officers during 2007.

Compensation Discussion and Analysis

The elements of executive compensation at Royale Energy consist mainly of cash salary and, if appropriate, a cash bonus at year end. The compensation committee makes recommendations to the board of directors annually on the compensation of the two top executives: the President and the Executive Vice President / Chief Financial Officer. See Compensation Committee Report. We do not have employment contracts with either of our executive officers.

Royale Energy also does not provide extensive personal benefits to its executives beyond those benefits, such as health insurance, that are provided to all employees. Each executive does receive an annual car allowance.

Stock Options and Equity Compensation

We did not grant any stock options, stock appreciation rights or non-equity incentive plan awards to our named executives and employees during 2007. No stock options were exercised by named executive officers in 2007, and none remained outstanding as of December 31, 2007. No nonqualified deferred compensation plans are in existence for named executives and employees. The named executives and employees are not beneficiaries or members of any defined compensation or other pension plans.

In March 2008, directors and executive officers of Royale Energy were each granted 45,000 options to purchase common stock at an exercise or base price of $3.50 per share, in consideration of their past service on the board. These options are to be vested in three parts, the first 15,000 vested March 31, 2008, and 15,000 will vest in each of the next two years March 31, 2009 and March 31, 2010. They were granted for a period of four years.

Compensation Committee Report

Our executive compensation policy is designed to motivate, reward and retain the key executive talent necessary to achieve our business objectives and contribute to our long-term success. Our compensation policy for our executive officers focuses primarily on determining appropriate salary levels and performance-based cash bonuses.

Policy

The compensation committee’s primary responsibility is making recommendations to the board of directors relating to compensation of our officers. The committee also makes recommendations to the board of directors regarding employee benefits, our defined benefit plans, defined contribution plans, and stock based plans.

Determination

To determine executive compensation, the committee, in December each year, meets with our officers to review our compensation programs, discuss the performance of the company, the duties and responsibilities of each of the officers pay levels and business results compared to others similarly situated within the industry. The committee then makes recommendations to the board of directors for any adjustment to the officers compensation levels.

Compensation Elements

Base. Base salaries for our executive officers are established based on the scope of their responsibilities, taking into account competitive market compensation paid by our peers. Base salaries are reviewed annually. The salaries we paid to our most highly paid executive officers for the last three years are set forth in the Summary Compensation Table included under Executive Compensation.

Bonus. The compensation committee meets annually to determine the quantity, if any, of the cash bonuses of executive officers. The amount granted is based, subjectively, upon the company’s stock price performance, earnings, revenue, reserves and production. The committee does not use quantifiable metrics for these criteria; but rather uses each in balance to assess the strength of the company’s performance. The committee believes that formulaic approaches to cash incentives can foster an unhealthy balance between short-term and long-term goals. In 2006, the compensation committee did not award bonuses to any of the company’s executive officers.

Members of the Compensation Committee:

Oscar A. Hildebrandt, Chair

Tony P. Hall

George M. Watters

Compensation of Directors

The following table describes the compensation paid to our directors who are not also named executives for their services in 2007.

Name	Fees Earned or Paid in Cash		All Other Compensation		Total
	($)		($)		($)
(a)	(b)		(c)		(d)
Harry E. Hosmer	$	167,717	$	13,444	$	181,161
Oscar A. Hildebrandt		19,168		-		19,168
George M. Watters		16,830		-		16,830
Gilbert C. L. Kemp		14,410		-		14,410
Gary Grinsfelder		10,808		-		10,808
Tony P. Hall		11,110		-		11,110
Rodney Nahama (former director)		3,905		-		3,905

Each director who is not an employee of Royale Energy receives a quarterly fee for his services, which in 2007 was set at $3,602.50. Committee members receive fees of $605 for attendance at each audit committee meeting and $302.50 for attendance at each compensation committee meeting. The Secretary receives an additional fee of $357.50 for attendance at each meeting. In addition, Royale Energy reimburses directors for the expenses they incur for their service.

No directors received any stock options or other equity based compensation in 2007. In March 2008, the directors and executive officers were awarded stock options for their past service. See Stock Options and Equity Compensation, page 6.

In addition, Royale Energy's Chairman of the Board and former President, Harry E. Hosmer, renders management consulting services to Royale Energy on an ongoing basis.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT OF ROYALE

The following table contains information regarding the ownership of Royale Energy’s common stock as of October 15, 2008, by:

i) each person who is known by Royale Energy to own beneficially more than 5% of the outstanding shares of each class of equity securities;

ii) each director of Royale Energy, and

iii) all directors and officers of Royale Energy as a group.

Except pursuant to applicable community property laws and except as otherwise indicated, each shareholder identified in the table possesses sole voting and investment power with respect to its or his shares. The holdings reported are based on reports filed with the Securities and Exchange Commission and the Company by the officers, directors and 5% shareholders pursuant to Section 16 of the Securities Exchange Act of 1934. Percentages are based on a total number of 8,505,630 outstanding shares of our common stock as of September 30, 2008, and individual percentages for each selling shareholder are calculated as provided in SEC Rule 13d-3. The mailing address of each listed stockholder is 7676 Hazard Center Drive, Suite 1500, San Diego, California 92108.

Stockholder (9)	Number		Percent

Donald H. Hosmer (3)		937,159		11.0	%

Harry E. Hosmer (3)		745,697		8.7	%

Oscar A. Hildebrandt		120,736		1.4	%

Stephen M. Hosmer (3)		1,163,427		13.6	%

Gilbert C. L. Kemp		64,942			*

Gary Grinsfelder		42,844			*

Tony P. Hall		46,250			*

George M. Watters		124,481		1.5	%

All officers and directors as a group (8 persons)		3,245,536		36.8	%

* Less than 1%

(1) Donald H. Hosmer is our Co-President, Co-Chief Executive Officer, Secretary and a member of our Board of Directors. Donald H. Hosmer is the son of Harry E. Hosmer, our Chairman of the Board.

(2) Harry E. Hosmer serves as our Chairman of the Board.

(3) Member of our Board of Directors.

(4) Stephen M. Hosmer is our Co-President, Co-Chief Executive Officer, Chief Financial Officer and a member of our Board of Directors. Stephen M. Hosmer is the son of Harry E. Hosmer, our Chairman of the Board.

(5) Includes 45,000 shares issuable on exercise of the 2008 Options.

(6) In June 2008, Harry E. Hosmer exercised 2008 Options to purchase 15,000 shares, and he holds 2008 Options to acquire an additional 30,000 shares.

(7) In June 2008, Stephen M. Hosmer exercised 2008 Options to purchase 15,000 shares, and he holds 2008 Options to acquire an additional 30,000 shares.

(8) In June 2008, Mr. Grinsfelder exercised 2008 Options for 10,000 shares of common stock in a cashless exercise and received a total of 6,844 shares of common stock in the transaction, after deduction of 3,166 option shares that were canceled as consideration for the purchase price. He therefore owns a total of 6,844 shares of common stock acquired pursuant to exercise of 2008 Options, and he holds 2008 Options to acquire an additional 35,000 shares.

(9) For each director and executive officer, includes options to purchase 15,000 shares of common stock, which vested on March 31, 2008.

ASPEN’S BUSINESS

The following description of Aspen’s business is derived from Aspen’s Annual Report on Form 10-KSB for the fiscal year ended June 30, 2008.

Summary of Aspen’s Business

Aspen was incorporated under the laws of the State of Delaware on February 28, 1980 for the primary purpose of acquiring, exploring and developing oil and gas and other mineral properties. Aspen’s principal executive offices are located at 2050 S. Oneida St., Suite 208, Denver, Colorado 80224-2426, (telephone 303-639-9860, facsimile 303-639-9863). Aspen’s websites are www.aspenexploration.com and www.aspnx.com. Aspen’s email address is aecorp2@qwestoffice.net. Aspen is currently engaged primarily in the exploration, development and production of oil and gas properties in California and Montana. Aspen has an interest in an inactive subsidiary: Aspen Gold Mining Co., a company that has not been engaged in business since 1995.

Oil and Gas Exploration and Development. Aspen’s major emphasis has been participation in the oil and gas segment, acquiring interests in producing oil or gas properties and participating in drilling operations. Aspen engages in a broad range of activities associated with the oil and gas business in an effort to develop oil and gas reserves. Aspen’s participation in the oil and gas exploration and development segment consists of two different lines of business –ownership of working interests and operating properties.

Aspen owns working interests in oil and gas wells. Aspen also owns working interests in properties, which it explores for oil or natural gas and, if Aspen’s exploration efforts are successful, it produces and sells oil or natural gas from those properties. Where Aspen holds working interests, it bears a proportionate share of the exploration and development costs of a property and if the property is successful will receive a proportionate return based on Aspen’s interest percentage. Aspen currently has working interests in 93 wells in the Sacramento Valley of northern California. Additionally, Aspen has non-operating working interests in 84 oil and gas wells located in the Williston Basin of Roosevelt County, Montana, 37 of which are currently productive.

Aspen also operates oil and gas wells and, where possible, it attempts to be the operator of each property in which it owns a working interest. As operator of oil and gas properties, Aspen manages exploration and development activities for the working interest owners (which includes Aspen) and accomplishes all of the administrative functions for the joint interest owners. The joint interest owners pay Aspen management fees for those services, which are recorded as a reduction to Aspen’s general and administrative expenses. All consideration received from sales or transfers of properties in connection with partnerships, joint venture operations, or various other forms of drilling arrangements involving oil and gas exploration and development activities are credited to the full cost account, except to the extent of amounts that represent reimbursement of organization, offering, general and administrative expenses, that are identifiable with the transaction, which are currently incurred and charged to expense. As of June 30, 2008, Aspen acts as the operator of 67 wells in the Sacramento Valley of northern California.

With the assistance of Aspen’s management, independent contractors retained from time to time, and, to a lesser extent, unsolicited submissions, Aspen has identified and will continue to identify prospects that it believes are suitable for drilling and acquisition. Currently, Aspen’s primary areas of interest are in California and Montana.

On September 4, 2008, Aspen announced that its board of directors decided to investigate strategic alternatives for Aspen, including the possibility of selling Aspen’s assets or considering another appropriate merger or acquisition transaction. Aspen’s board determined to make this investigation for several reasons, including:

The disproportionate cost of Aspen’s general and administrative expenditures required as a result of compliance with the Securities Exchange Act of 1934, as amended (including the requirements of the Sarbanes-Oxley Act of 2002) when compared to Aspen’s revenues and net income;

The board of directors’ belief that the market price of Aspen common stock does not adequately reflect the inherent value of Aspen’s producing oil and gas assets and undeveloped acreage, and thus the board of directors does not believe that a transaction based on the value of Aspen’s common stock would be in the best interest of Aspen’s shareholders; and

The likelihood that Aspen’s president will be unable to resume his former role and responsibilities and oversee Aspen’s day-to-day operations due to the effects of the stroke he suffered in January 2008.

Aspen has opened a data room in Santa Barbara, California, at which persons interested in acquiring Aspen’s assets or Aspen itself will be able to review a significant amount of information about Aspen and its properties. Aspen has retained Brian Wolf, a California-licensed mineral, oil and gas broker and consulting geologist, to assemble and operate the data room for Aspen.

As of the date of this prospectus, Aspen had not announced that it has received any offer from any person for an asset acquisition, merger, or other business combination. Aspen has stated that it may later determine that it is in the best interest of Aspen’s shareholders to investigate other forms of business alternatives or to continue and expand existing business operations with existing or new management. In the meantime, Aspen will continue to carry on its business operations in the normal course.

Company Strategy

Aspen holds working interests in oil and gas properties, many of which have wells producing oil or natural gas. Where Aspen acquires an interest in a property or acreage on which exploration or development drilling is planned, Aspen will seldom assume the entire risk of acquisition or drilling. Rather, Aspen prefers to assess the relative potential and risks of each prospect and determine the degree to which it will participate in the exploration or development drilling. Generally, Aspen has determined that it is beneficial to invite industry participants to share the risk and the reward of the prospect by financing some or all of the costs of drilling contemplated wells, and as such have entered into industry standard joint operating agreements with other parties. In such cases, Aspen may retain a carried working interest, a reversionary interest, or other promotional interest, and Aspen generally is required to finance all or a portion of Aspen’s proportional interest in the prospect. Although this approach reduces Aspen’s potential return should the drilling operations prove successful, it also reduces Aspen’s risk and financial commitment to a particular prospect. Fees assessed for the participation in these prospects are credited to the full-cost pool.

Conversely, Aspen may from time to time participate in drilling prospects offered by other persons if Aspen believes that the potential benefit from the drilling operations outweighs the risk and the cost of the proposed operations. This approach allows Aspen to diversify into a larger number of prospects at a lower cost per prospect, but these operations (commonly known as “farm-ins”) are generally more expensive than operations where Aspen offers the participation to others (known as “farm-outs”). During the year ended June 30, 2008, Aspen participated in the drilling of 6 farm-in wells.

In addition to properties having producing wells or reserves, Aspen also owns some unproved properties that it believes might have value for oil and gas exploration and development. Aspen does not believe that its capitalized costs associated with these unproved properties are, at June 30, 2008, material in amount. Such costs include lease acquisition, geological and geophysical work, and delay rentals. These costs are capitalized in Aspen’s full cost pool and included in Aspen’s amortization computation. Aspen reviews the capitalized costs of all properties against Aspen’s full-cost pool on a quarterly basis.

Aspen also occasionally acquires unevaluated acreage in conjunction with the purchase of oil and gas leases. While unproved properties are properties Aspen believes are valuable for oil and gas exploration based on the exploration work performed, unevaluated properties are properties that have been acquired but which have not been evaluated based on exploration work known to have been performed by others. Costs attributable to unevaluated acreage are considered immaterial at June 30, 2008. These costs are included in Aspen’s full cost pool and amortization computation.

From time to time Aspen may also engage in mineral and natural resource exploration and similar business activities not associated with the oil and gas industry. To date, Aspen has not devoted a material amount of resources to these other business activities nor has Aspen generated material revenues from these other business activities. In January 2007 (effective September 1, 2006) Aspen entered into a joint venture with Hemis Corporation whereby Hemis became the operator of a venture engaged in permit acquisition and exploration for commercial quantities of gold in and near Cook Inlet, Alaska. Hemis paid Aspen $50,000 in January 2007 and another $50,000 in August 2007. Hemis was obligated to pay Aspen another $50,000 on or before September 1, 2008 and on each anniversary date until production of gold begins. Hemis did not make the 2008 payment to Aspen, and Aspen has provided notification to Hemis of Aspen’s intention to terminate that agreement. Aspen has stated that the agreement will be terminated unless Hemis cures the payment default and certain other defaults within the 30 day notice period. Aspen has stated that it does not know if Hemis will cure the payment default or contest the existence of the other defaults that Aspen alleged.

In the agreement with Hemis, Aspen retained a 5% gross royalty on production. In June 2007, Hemis announced that it had begun a preliminary oceanographic survey of the gold project and was optimistic regarding the project’s potential. Hemis has provided information to Aspen from the 2007 survey.

As discussed above, Aspen is also considering the possibility of selling Aspen’s properties or entering into another type of business combination. Aspen has stated that it is continuing to conduct Aspen’s business in the ordinary course while it is exploring these alternatives.

Principal Products Produced and Services Rendered. Aspen’s principal products during fiscal 2008 were crude oil and natural gas. Crude oil and natural gas are generally sold to various entities, including pipeline companies, which usually service the area in which Aspen’s producing wells are located. In the fiscal year ended June 30, 2008, Aspen’s crude oil and natural gas sales totaled $5,390,367.

Both Aspen’s produced crude oil and natural gas are subject to pricing in the local markets where the production occurs. It is customary that such products are priced based on local or regional supply and demand factors. California heavy crude sells at a discount to WTI, the U.S. benchmark for crude oil, primarily due to the additional cost to refine gasoline or light product out of a barrel of heavy crude. Natural gas field prices are normally priced off of Henry Hub NYMEX price, the benchmark for U.S. natural gas. Aspen’s gas prices are based on the PG&E Citygate Index. While Aspen attempts to contract for the best possible price in each of Aspen’s producing locations, there is no assurance that past price differentials will continue into the future. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the mid-stream or downstream sectors of the industry, trade restrictions, governmental regulations, and other factors. Aspen may be adversely impacted by a widening differential on the products sold.

Distribution Methods of the Products or Services. Aspen is not involved in the distribution aspect of the oil and gas industry. Aspen sells its produced natural gas and oil to third parties for distribution.

Competitive Business Conditions. The exploration for, and development, production and acquisition of, oil, gas, precious metals and other minerals are subject to intense competition. The principal methods of compensation to third parties for the acquisition of oil and gas and other mineral properties are the payment of:


(i)		cash bonuses at the time of the acquisition of leases;
(ii)		delay rentals and the amount of annual rental payments;
(iii)		advance royalties and the use of differential royalty rates; and
(iv)		stipulations requiring exploration and production commitments by the lessee.

Some of Aspen’s current competitors, and many of Aspen’s potential competitors, in the oil and gas industry have vast experience, are larger and have significantly greater financial resources, existing staff and labor forces, equipment, and other resources than does Aspen. Consequently, these competitors may be in a better position to compete for oil and gas projects. Because of Aspen’s relatively small size, it has a minimal competitive position in the oil and gas industry.

In addition, the availability of a ready market for oil and gas depends upon numerous factors beyond Aspen’s control, including the overall amount of domestic production and imports of oil and gas, the proximity and capacity of pipelines, and the effect of federal and state regulation of oil and gas sales, as well governmental environmental regulations applicable to the exploration, production and usage of oil and gas. Aspen expects that competition for leasing of oil and gas prospects will become even more intense in the future.

Sources and Availability of Raw Materials. As part of the business of engaging in the operation of oil and gas properties, Aspen depends on such items as drilling rigs and other equipment, casing pipe, drilling mud and other supplies and equipment necessary for Aspen’s operations. At the present time, drilling rigs are in short supply, and are demanding a premium price. Aspen has stated that it has been able to obtain the services of drilling rigs when needed for Aspen’s exploration and development activities.

Most other items that Aspen needs have been commonly available from a number of sources. Although Aspen does not foresee a shortage in supply or foresee having difficulty in acquiring any equipment relevant to the conduct of business, Aspen cannot offer any assurances that the necessary equipment will be available or that Aspen will be able to acquire the items on economically feasible terms.

Dependence Upon One or a Few Major Customers. Aspen generally sells its oil and gas production to a limited number of companies. In fiscal 2008 Aspen obtained more than 10% of its revenues from sales to Calpine Corporation and Enserco Energy, Inc. (33% and 61%, respectively). Aspen has stated that it does not believe the loss of these customers would adversely impact Aspen’s revenues because Aspen believes that oil and gas sales are primarily market driven and are not dependent on particular purchasers. Consequently, Aspen believes that substitute purchasers would be available based on the widespread uses of and the need for oil and gas. However, Aspen cannot guarantee that the loss of either of these major customers would not negatively impact Aspen’s business operations and revenues.

Need for Governmental Approval of Principal Products or Services. Aspen does not need to seek government approval of Aspen’s principal products.

Effect of Existing or Probable Governmental Regulation. Oil and gas exploration and production are open to significant governmental regulation including worker health and safety laws, employment regulations and environmental regulations. Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. These regulations affect Aspen’s operations and limit the quantity of oil and natural gas it may produce and sell. Operations that occur on public lands may be subject to further regulation by the Bureau of Land Management, the U.S. Army Corps of Engineers, or the U.S. Forest Service as well as other federal and state agencies.

A major risk inherent in Aspen’s drilling plans is the need to obtain drilling permits from state, and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a negative effect on Aspen’s ability to explore on or develop its 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 Aspen’s profitability .

Estimate of Amounts Spent on Research and Development Activities. Aspen has not engaged in any material research and development activities since its inception.

Costs and Effects of Compliance with Environmental Laws (federal, state and local). Because Aspen is engaged in extracting natural resources, Aspen’s business is subject to various federal, state and local provisions regarding environmental and ecological matters. Therefore, compliance with environmental laws may necessitate significant capital outlays, affect Aspen’s earnings potential, and cause material changes in Aspen’s current and proposed business activities.

At the present time, however, the environmental laws do not materially hinder nor adversely affect Aspen’s business. Capital expenditures relating to environmental control facilities have not been material to Aspen’s operations since Aspen’s inception.

Employees

As of June 30, 2008, Aspen had 2 full-time employees and 1 part-time employee. Aspen also employs independent contractors and other consultants, as needed.

ASPEN’S PROPERTIES

The following description of Aspen’s properties is derived from Aspen’s Annual Report on Form 10-KSB for the fiscal year ended June 30, 2008.

Drilling and Acquisition Activity

During the fiscal year ended June 30, 2008, Aspen participated in the drilling of 11 gross (3.295 net) operated wells, 7 of which were completed as gas wells, and 1 is in process, for a 64% success ratio. The estimated lives of the individual wells drilled during the fiscal year range from 1 to 20 years. Of the 7 successful gas wells drilled during the 2008 fiscal year, 2 gas wells were drilled in the West Grimes Field, 1 gas well was drilled in the Grimes Field, 2 gas wells were drilled in the Malton Black Butte Field, 1 gas well was drilled in the Butte Sink Field, and 1 gas well was drilled in the Cache Creek Field.

In February 2007, Aspen purchased an interest in approximately 84 oil wells, 37 of which are currently producing (4.625 net) in certain oil producing assets encompassing 22,600 acres in the East Poplar Unit and the Northwest Poplar Field in Roosevelt County, Montana located in the Williston Basin.

Through December 2007, Aspen was obligated to pay 12.5% of the expenses of operations for a 10% working interest. Since Aspen’s investment did not reach payout as of January 1, 2008, Aspen’s expense obligation was reduced to 10%. At payout, Aspen’s working interest will proportionately be reduced also. As of June 30, 2008, there remains $1,315,211 until Aspen reaches payout, based on total revenues received through June 30, 2008 of $984,590. Commencing February 2008, Aspen (and the other working interest participants) agreed that the operator could retain 60% of the cash flow from the producing wells (after deduction of royalties, taxes, expenses and loan payment) for capital projects, geology and engineering (amounting to a total of $96,250 to Aspen’s account as of June 30, 2008). The operator has used these funds for capital expenses, workovers and recompletions. Additionally, in May 2008 Aspen amended its participation agreement in the Poplar Unit to separately market and deal with the “deeper rights,” oil and gas rights below the base of the Mission Canyon Formation and to grant one of the participants the right to seek to farmout the deeper rights. To the extent that Aspen has available capital and has identified other appropriate drilling or exploration opportunities, Aspen may participate in the drilling of additional wells.

Aspen’s decisions to develop and operate prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies. Because of these factors, Aspen could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on Aspen’s future cash flows, results of operations and financial position.

Below is a summary of Aspen’s primary drilling and acquisition activity occurring during its 2008 fiscal year and its activities conducted during its 2009 fiscal year by geographic areas.

West Grimes Field, Colusa County, California

The first 18 wells drilled in the West Grimes Gas Field were successful. These wells were drilled based on a 10.5 square mile 3-D seismic program located over a portion of Aspen’s 10,000 plus leased acres in this field. Aspen believes several additional excellent drilling prospects have been identified. The wells in this field produce from multiple Forbes intervals ranging in depth from 6,000 feet to 8,500 feet and have produced over 80 billion cubic feet (BCF) of gas to date. Numerous wells in this immediate area have produced at very prolific flow rates (4,000 MCFPD), have yielded excellent per well reserves (3 to 4 BCF per well), and have long productive well lives. Several of the 10 producing wells that Aspen acquired in this field in 2003 have been producing for 40 years. Aspen believes that several of these wells may have additional gas potential in behind-pipe zones, which have not yet been perforated. Aspen’s operated working interests in this field range from 21% to 34%.

The Morris #12-4 well was drilled in July 2007 to a depth of 8,007 feet and encountered approximately 115 feet of potential gross gas pay in several intervals in the Forbes formation. Production casing was run based on favorable mud log and electric log responses. Several of these intervals were perforated and tested gas on a ¼ inch choke at a stabilized flow rate of 500 MCFPD. The shut in tubing and shut in casing pressures were 3,150 psig. Aspen has a 21% operated working interest in this well. Gas sales commenced on September 25, 2007.

In August 2007, the WGU #15-14 well was directionally drilled to a depth of 7,770 feet and encountered approximately 80 feet of potential gross gas pay in several intervals in the Forbes formation. One of these intervals was perforated and tested gas on a 1/4 inch choke at a stabilized flow rate of 1,130 MCFPD. The shut in tubing and shut in casing pressures were 3,200 psig. Aspen has a 34% operated working interest in this well. Gas sales commenced on August 28, 2007.

The Harlan #1-24 well was drilled to a depth of 8,250 feet and encountered approximately 70 feet of potential gross gas pay in several intervals in the Forbes formation. Production casing was run based on favorable mud log and electric log responses. One of these intervals was perforated and tested gas on a 3/16 inch choke at a stabilized flow rate of 1,700 MCFPD. The shut in tubing and shut in casing pressures were 3,740 psig. Aspen has a 34% working interest in this well. Gas sales commenced on February 28, 2008. This was the eighteenth successful gas well out of eighteen attempts by Aspen in this field.

Aspen acquired a 12-square mile 3D-seismic survey directly south of Aspen’s successful West Grimes project in Colusa County, California. Seismic processing has been completed on the new Strain Ventures project, which encompasses parts of the West Grimes and Buckeye Gas Fields, and includes a sparsely drilled area west of these fields. Aspen plans to drill at least two prospects identified on the new 3D-survey in the fall of 2008, contingent upon rig availability and approval of necessary permits. Aspen has a 32% working interest in the Strain Ventures project.

Malton Black Butte, Glenn and Tehama Counties, California

Aspen has successfully drilled 10 gas wells out of 12 attempts in this field during the last 5 fiscal years. These wells produce from multiple horizons in the Kione and Forbes formation from depths ranging from 1,700 feet to 5,000 feet. Aspen has operated working interests in these wells ranging from 21% to 36%.

The Johnson Unit #12 well was drilled to a depth of 4,700 feet and encountered potential gas pay in several intervals in the Forbes formation. Production casing was run based on favorable mud log and electric log responses. One of these Forbes intervals was perforated and tested gas on a 3/16 inch choke at a stabilized rate of 141 MCFPD. Gas sales commenced on October 27, 2006. Aspen has a 36% operated working interest in this well Aspen has drilled the Johnson Unit #13 well in its Johnson Unit of the Malton Black Butte Field. The Johnson Unit #13 well was drilled to a depth of 4,896 feet and encountered approximately 125 feet of potential gross gas pay in several intervals in the Forbes formation. Production casing was run based on favorable mud log and electric log responses. One of the intervals was perforated and tested gas on a 12/64” choke at a rate of 668 MCFPD. Aspen has a 31.00% operated working interest in this well.

This well is in the same Unit as Aspen’s Johnson #11 well completed in August 2005. Aspen has a 31% working interest in the Johnson #11 and #13 wells. Aspen has a lesser interest in the Elektra Unit which overlaps a portion of the Johnson Unit and which may impact the Merrill #31-1 well (which is not specifically included in the Elektra or the Johnson Unit) in addition to the Johnson #11, #12, and #13 wells. Aspen is attempting to define its interests in those wells and has not commenced producing from the Johnson #13 well. The existence of a title deficiency can adversely impact the economic results of even a successful well. To the extent that it proves that Aspen’s interests in the Johnson #11, #12, and #13 wells or the Merrill #31-1 well are impacted by the overlapping Elektra unit, Aspen (as operator of the wells) will likely have to make certain economic adjustments although those will be determined later based on a full legal review. At the present time, Aspen has not been able to quantify the potential liability, if any, and cannot offer any assessment as to the likelihood that any liability will be recognized or to determine whether the likelihood of an unfavorable outcome on any potential claim regarding the its wells in the Johnson Unit or the Merrill #31-1 well is either probable or remote. However, Aspen believes that it has meritorious defenses to any such potential claim.

The Eastby #1-1 well was drilled to a depth of 5,010 feet and encountered approximately 45 feet of potential gross gas pay in several intervals in the Eocene and Forbes formations. Production casing was run based on favorable mud log and electric log responses. One of the intervals was perforated and tested gas on a 12/64” choke at a rate of 351 MCFPD. Aspen has a 30.00% operated working interest in this well. Gas sales commenced August 1, 2008.

Aspen has agreed to participate in a new exploration program operated by a third party in the Malton area in Glenn and Tehama Counties, California. This area is east of Aspen’s Malton Black Butte project. Several prospects have been identified by the Operator in this area, and drilling began in Spring, 2008. To date, the third party has drilled 4 successful gas wells. Aspen has agreed to acquire a non-operated 7% working interest in the project.

Butte Sink Gas Field

The Delta Farms #10 well was directionally drilled to a depth of 5,600 feet and encountered over 100 feet of potential gross gas pay in several intervals in the Forbes and Kione formations. Production casing was run based on favorable mud log and electric log responses. Aspen has additional potential locations based on 3-D seismic data and well control on its 1,000 acre leasehold in this field. Aspen owns a 38% operated working interest before payout and a 44.3% working interest after payout in this well. Gas sales commenced November 28, 2007.

Cache Creek Gas Field, Yolo County, California

The SJDD #11-1 well was drilled to a depth of 4,111 feet and encountered approximately 24 feet of potential gross gas pay in two intervals in the Starkey formation. One of these intervals was perforated and tested gas on a 10/64” choke at a stabilized flow rate of 750 MCFPD and 1380 psig flowing casing pressure. The shut in tubing pressure was 1440 psig and shut in casing pressure was 1500 psig. Aspen has a 30% operated working interest in this well. Gas sales commenced May 20, 2008.

In the Sacramento Valley, Aspen has drilled 49 successful gas wells out of 56 attempts during the last 5 years (88% success rate) and drilled 57 successful gas wells out of 68 attempts during the last 7 years, a success rate of 84%.

Poplar Field, Roosevelt County, Montana

In February 2007, Aspen purchased from Nautilus Poplar, LLC, a non-operating working interest in certain oil producing assets encompassing 22,600 acres in the East Poplar Unit and the Northwest Poplar Field in Roosevelt County, Montana located in the Williston Basin. These properties contain a total of 37 producing oil wells, and 7 salt-water disposal wells. Current production is 230 gross BOPD from the Charles “B” reservoir.

The crude oil is 40^oAPI sweet and is readily marketed at the lease boundary. All produced water is disposed within the Unit boundary.

In May 2008 Aspen amended its participation agreement in the Poplar Unit to separately market and deal with the “deeper rights,” oil and gas rights below the base of the Mission Canyon Formation and to grant one of the other participants the right to seek to farmout the deeper rights. To the extent that Aspen has available capital and has identified appropriate drilling or exploration opportunities, Aspen may participate in the drilling of additional wells.

Aspen believes that the acquisition has provided it with diversification into long-lived oil reserves. There is also upside reserve potential via increased water disposal capacity, re-activation of old wells, water shut off techniques, behind-pipe potential in the Charles A, B, & C, and drilling potential in the Mission Canyon and Nisku. This acquisition also provides ownership in 3-D seismic data over 22,600 acres.

The initial cost to Aspen for its 12.5% before payout working interest (including its share of the acquisition costs) was approximately $1,450,000, which Aspen paid using its working capital and bank dept (a total of approximately $1,075,000) and its 12.5% share ($375,000) of the $3,000,000 loan obtained by Nautilus in connection with the purchase. Aspen also paid an additional $400,000 of anticipated capital expenditures during the first year and $275,667 during our year ended June 30, 2008.

Drilling Activity

The following table sets forth the results of Aspen’s drilling activities during the fiscal years ended June 30, 2006, 2007 and 2008:

	Drilling Activity
			Gross Wells						Net Wells
Year	Total		Producing		Dry		Total		Producing		Dry

2006 Exploratory		14		13		1		3.69		3.34		0.35
2007 Exploratory		11		8		3		2.93		2.15		0.78
2008 Exploratory		11		7		4		3.295		2.18		1.115

Aspen did not drill any development wells during the past three fiscal years, or subsequently.

Production Information:

Net Production, Average Sales Price and Average Production Costs (Lifting)

The table below sets forth the net quantities of oil and gas production (net of all royalties, overriding royalties and production due to others) attributable to Aspen for the fiscal years ended June 30, 2008, 2007, and 2006, and the average sales prices, average production costs and direct lifting costs per unit of production.

	Years Ended June 30,
	2008		2007		2006
Net Production
Oil (Bbls)		10166		3986		176
Gas (MMbtu)		582		598		696

Average Sales Prices
Oil (per Bbl)	$	96.65	$	58.30	$	81.12
Gas (per MMbtu)	$	7.58	$	7.00	$	7.76

Average Production Cost¹
Per equivalent
Bbl of oil	$	36.36	$	27.04	$	17.81

Average Lifting Costs²
Per equivalent
Bbl of oil	$	13.59	$	8.08	$	4.63

¹Production costs include depreciation, depletion and amortization, lease operating expenses and all associated taxes.

²Direct lifting costs do not include impairment expense, ceiling write-down, or depreciation, depletion and amortization.

Productive Wells and Acreage

Gross and Net Productive Gas Wells, Developed Acres, and Overriding Royalty Interests

Leasehold Interests - Productive Wells and Developed Acres. The tables below set forth Aspen's leasehold interests in productive and shut-in gas wells, and in developed acres, at June 30, 2008:

Producing and Shut-In Wells
	Gross		Net¹
	Gas		Gas
		93		19.32824

California

	Gross		Net¹
	Oil		Oil
Montana		37		4.62500

¹A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

Developed Acreage
	Aspen's Developed Acres¹
County	Gross²		Net³

California:
Colusa		6,137		1,434
Glenn		1,356		281
Kern		120		22
Solano		1,431		341
Sutter		1,663		389
Tehama		1,654		396
Yolo		280		78

TOTAL		12,641		2,941

¹Consists of acres spaced or assignable to productive wells.

²A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

³A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Royalty Interests in Productive Wells and Developed Acreage. The following tables set forth Aspen's royalty interest in productive gas wells and developed acres at June 30, 2008:

Overriding Royalty Interests
			Productive
			Wells		Gross
Prospect	Interest (%)		Gas		Acreage¹

California:
Malton Black Butte		5.926365		3		765
Momentum		3.671477		2		320
Grimes Gas		0.101590		1		615

TOTAL				6		1,700

¹Consists of acres spaced or assignable to productive wells.

Undeveloped Acreage

Leasehold Interests Undeveloped Acreage. The following table sets forth Aspen's leasehold interest in undeveloped acreage at June 30, 2008:

	Undeveloped Acreage
	Gross		Net
California:
Colusa		12,124		3,083
Kern		2,594		338
Solano		1,394		1,273
Sutter		173		52

TOTAL		16,285		4,746

Gas Delivery Commitments

Aspen has entered into a series of gas sales contracts with Enserco Energy, Inc. and Calpine Producer Services, L.P. In each of the contracts, the purchasers are required to purchase the stated quantities at stated prices, less transportation and other expenses. The contracts contain monetary penalties for non-delivery of the gas. The following table sets forth some additional information about those contracts:

Aspen expects to have sufficient gas available for delivery to Enserco and Calpine from anticipated production from our California fields. Aspen’s sales of natural gas under the contracts qualify for the “Normal Purchases and Normal Sales” exception in paragraph 10(b) of FAS 133. The contract is a normal industry sales contract that provides for the sale of gas over a reasonable period of time in the normal course of business.

Present Activities

As of June 30, 2008, Aspen was the operator of 67 gas wells, had a non-operated interest in 26 additional gas wells, and had a non-operating working interest in approximately 84 oil wells in Montana, 37 of which are currently producing. During fiscal 2008, Aspen commenced drilling on approximately 11 gas wells in the Sacramento Valley gas province of northern California.

Drilling Commitments

Aspen has a proposed drilling budget for the period July 2008 through June 2009. The budget includes drilling two gas wells in the Sacramento gas province of northern California. Aspen’s share of the estimated costs to complete this program is set forth in the following table:

					Completion
					Equipping
Area	Wells		Drilling		Costs		Total

West Grimes Field
Colusa County, CA		2	$	480,000	$	288,000	$	768,000

Total		2	$	480,000	$	288,000	$	768,000

The proposed drilling budget only includes the wells that we have already budgeted. It can be expected that Aspen will drill several wells in addition to the two included in its current budget. Aspen has not identified locations for those additional drilling activities, however.

Reserve Information – Oil and Gas Reserves

Estimated Proved Reserves/Developed and Undeveloped Reserves. The following tables set forth the estimated proved developed and proved undeveloped oil and gas reserves of Aspen for the years ended June 30, 2008 and 2007. See Note 6 to Aspen’s Consolidated Financial Statements and the above discussion.

Estimated Proved Reserves
Proved Reserves	Oil (Bbls)			Gas (Mcf)

Estimated quantity, June 30, 2006		1,838			2,750,716

Revisions of previous estimates		(79	)		(325,865	)
Discoveries		-			874,010
Acquisitions		132,072			-
Production		(3,986	)		(597,660	)

Estimated quantity, June 30, 2007		129,845			2,701,201

Revisions of previous estimates		71,656			(337,674	)
Discoveries		-			382,828
Acquisitions		-			-
Production		(10,166	)		(595,621	)

Estimated quantity, June 30, 2008		191,335			2,150,734

Developed and Undeveloped Reserves
	Developed		Undeveloped		Total
Oil (Bbls)
June 30, 2008		191,335		-		191,335
June 30, 2007		129,845		-		129,845

Gas (Mcf)
June 30, 2008		2,150,734		-		2,150,734
June 30, 2007		2,701,201		-		2,701,201

For information concerning the standardized measure of discounted future net cash flows, estimated future net cash flows and present values of such cash flows attributable to our proved oil and gas reserves as well as other reserve information, see Note 6 to Aspen’s Consolidated Financial Statements.

Oil and Gas Reserves Reported to Other Agencies. Aspen did not file any estimates of total proved net oil or gas reserves with, or include such information in reports to, any federal authority or agency during the fiscal year ended June 30, 2008, or subsequently thereafter.

Title Examinations: Oil and Gas. As is customary in the oil and gas industry, Aspen performs only a perfunctory title examination at the time of acquisition of undeveloped properties. Prior to the commencement of drilling, in most cases, and in any event where Aspen is the operator, a thorough title examination is typically conducted and significant defects are usually remedied before proceeding with operations. Aspen believes that the title to its properties is generally acceptable to a reasonably prudent operator in the oil and gas industry. As described above, Aspen has identified certain title issues that may affect our Johnson #11, #12 and #13 wells (which are included within the Johnson Unit of the Malton Black Butte Field and the overlapping Elektra unit) and the Merrill #31-1 (which is not included in the Johnson or Electra Units). As a result of these issues, Aspen may be required to make certain economic adjustments, although any requirement to make any economic adjustments and the scope or amount of those possible adjustments have not yet been determined. At the present time, Aspen has not been able to quantify the potential liability, if any, and cannot offer any assessment as to the likelihood that any liability will be recognized or to determine whether the likelihood of an unfavorable outcome on any potential claim regarding its wells in the Johnson Unit or the Merrill #31-1 well is either probable or remote. However, Aspen believes that it has meritorious defenses to any such potential claim. The properties Aspen owns are subject to royalty, overriding royalty and other interests customary in the industry, liens incidental to operating agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. Aspen does not believe that any of these burdens materially detract from the value of the properties or will materially interfere with its business.

Aspen has purchased producing properties on which no updated title opinion was prepared. In such cases, Aspen has retained third party certified petroleum landmen to review title.

Office Facilities

Aspen’s principal office is located in Denver, Colorado. Aspen also has an office located in Bakersfield, California. The Denver office consists of approximately 1,108 square feet with an additional 750 square feet of basement storage. Aspen entered into a lease agreement on May 1, 2008 for a period of one year, to continue thereafter on a month-to-month basis for a lease rate of $1,261 per month.

Aspen entered into a lease agreement for its Bakersfield, California office, which consists of approximately 546 square feet. The Bakersfield, California lease payments are $901-$934 per month over the term of the lease, which expired July 31, 2008 and was extended until December 31, 2008.

ASPEN IS NOT PARTY TO ANY LEGAL PROCEEDINGS

Aspen is not , to Royale’s knowledge, subject to any pending or threatened, legal proceedings.

MARKET FOR ASPEN’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The following description of the market for Aspen’s common equity and related stockholder matters is derived from Aspen’s Annual Report on Form 10-KSB for the year ended June 30, 2008, and independent stock market price reports.

Market Information

Aspen’s common stock is quoted on the Over-the-Counter Bulletin Board (“OTCBB”) under the symbol "ASPN". The following table sets forth the quarterly high and low prices of Aspen’s Common Stock from January 2006 through September 2008. The quotations reflect inter-dealer prices without retail mark-up, mark-down or commission and may not reflect actual transactions

	1^st Qtr				2^nd Qtr				3^rd Qtr				4^th Qtr
	High		Low		High		Low		High		Low		High		Low
2008		2.55		1.66		3.12		1.85		2.76		1.50
2007		3.00		2.23		3.95		2.41		3.87		2.97		3.45		2.06
2006		6.50		4.17		5.22		3.58		5.40		3.50		4.09		2.88

As of June 30, 2008, there were approximately 1,020 holders of record of Aspen’s Common Stock. This does not include an indeterminate number of persons who hold our Common Stock in brokerage accounts and otherwise in ‘street name.’

Dividends:

Holders of common stock are entitled to receive such dividends as may be declared by Aspen’s Board of Directors. On November 8, 2006, Aspen declared a cash dividend in the amount of $0.05 per share. A total of $357,981 was paid to the shareholders on December 6, 2006, as determined by shareholders of record as of November 20, 2006. No dividends were declared or paid during the 2008 fiscal year. Decisions concerning dividend payments in the future will depend on income and cash requirements. There are no contractual restrictions on our ability to pay dividends to our shareholders.

Securities Authorized for Issuance Under Equity Compensation Plans

The following is provided with respect to compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance as of the fiscal year ending June 30, 2008.

Equity Compensation Plan Information¹
					Number of Securities
					Remaining Available
	Number of Securities				for Future Issuance
	to be Issued Upon		Weighted-Average		Under Equity
	Exercise of		Exercise Price of		Compensation Plans
	Outstanding Options,		Outstanding Options,		(Excluding Securities
Plan Category	Warrants, and Rights		Warrants, and Rights		Reflected in Column (a))
and Description	(a)		(b)		(c)

Equity Compensation Plans
Approved by Security Holders		-	$	-		-

Equity Compensation Plans Not
Approved by Security Holders		887,098		2.17		342,902

Total		887,098	$	2.17		342,902

¹This does not include options held by management and directors that were not granted as pursuant to a compensation plan or compensation arrangement. In each case, the disclosure refers to options or warrants unless otherwise specifically stated.

Recent Sales of Unregistered Securities

There were no sales of unregistered securities by Aspen during the fiscal year ended June 30, 2008 or subsequently that were not previously disclosed in a quarterly report on its Form 10-QSB or a current report on Form 8-K.

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

The following is derived from “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Aspen’s Annual Report on Form 10-KSB for the fiscal year ended June 30, 2008, and Aspen’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008, and represents Aspen’s analysis of its historical financial condition and results of operations.

Overview:

Since 1996, Aspen has focused its efforts on the exploration, development and operation of natural gas properties in the Sacramento Valley of northern California, and in 2007 it acquired interests in oil properties in Montana. Aspen’s business activities are primarily focused in two separate aspects of the oil and gas industry:


(1	)	holding and acquiring operating interests in oil and gas properties where Aspen acts as the operator of oil
		and gas wells and properties; and

(2	)	holding non-operating interests in oil and gas properties.

As of June 30, 2008, Aspen was the operator of 67 gas wells in the Sacramento Valley of northern California. Additionally, Aspen had a non-operated interest in 26 gas wells in the Sacramento Valley of northern California and non-operating working interest in approximately 37 oil wells in Montana. When appropriate Aspen may engage in business activities related to the exploration and development of other minerals and resources.

Where possible, Aspen attempts to be the operator of each property in which we invest. Aspen believes that its knowledge of drilling and operating wells in the Sacramento Valley allows it to maximize the potential return of each property. In addition, the other working interest owners are obligated to pay Aspen fees pursuant to the “overhead reimbursement” provisions of the COPAS Accounting Procedures which are included as an attachment to the operating agreements. These accounting procedures define the overhead expenses that are charged to the joint accounts and permit Aspen to charge some expenses (such as “salaries, wages and Personal Expenses of Technical Employees directly employed on the Joint Property” and drilling expenses) directly to the joint interest owners. In almost all cases, Aspen also charges a general monthly producing overhead rate per well. Aspen does not recognize these fees received from the joint interest owners as revenues; rather they are offset against (and are a deduction from) Aspen’s general and administrative expenses as reflected in its statement of operations. During the fiscal year ended June 30, 2008, these administrative charges to the properties help cover approximately 49% of Aspen’s selling, general and administrative expenses.

On September 4, 2008, subsequent to fiscal year end, Aspen announced that it had decided to investigate strategic alternatives, including the possibility of selling Aspen’s assets or considering another appropriate merger or acquisition transaction. Aspen has opened a data room where interested persons may review certain information about our properties. Aspen cannot offer any assurance that it will receive an acceptable offer from any person for an asset acquisition, merger, or other business combination. Further, Aspen may later determine that it is in the best interest of its shareholders to investigate other forms of business alternatives or to continue and expand existing business operations with existing or new management. In the meantime, Aspen is carrying on its business operations in the normal course.

Critical Accounting Policies and Estimates:

Aspen believes the following critical accounting policies affect its most significant judgments and estimates used in the preparation of its Consolidated Financial Statements.

Reserve Estimates

Aspen’s estimates of oil and natural gas reserves, by necessity, are projections based on an interpretation of geologic and engineering data. There are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of Aspen’s oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Many factors will affect actual future net cash flows, including:

the amount and timing of actual production;

supply and demand for oil and natural gas;

curtailments or increases in consumption by purchasers; and

changes in governmental regulations or taxation.

Gas Delivery Commitments

Aspen has entered into contracts for the sale and purchase of natural gas with Enserco Energy Inc., and Calpine Producer Services, L.P. The original, master contract with Enserco is dated November 1, 2005. The master contract with Calpine is dated June 1, 2007. Aspen has continuously renewed these contracts with Enserco and Calpine since then. Aspen’s sales of natural gas under the Enserco and Calpine contracts qualify for the “Normal Purchases and Normal Sales” exception in paragraph 10(b) of FAS 133. The contracts are normal industry sales contracts that provide for the sale of gas over a reasonable period of time in the normal course of business. The contracts contain net settlement provisions should Aspen fail to deliver natural gas when required. Those provisions are mutual and establish the sole and exclusive remedy of the parties in the event of a breach of a firm obligation to deliver or receive natural gas as agreed.

Property, Equipment and Depreciation

Aspen follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, including salaries, benefits and other internal salary related costs directly attributable to these activities. All capitalized costs are depleted on a composite units-of-production method based on estimated proved reserves attributable to the oil and gas properties owned by Aspen. Costs associated with production and general corporate activities are expensed in the period incurred. When Aspen acts as operator of its producing wells, it receives management fees for these services, which serve to offset its selling, general, and administrative expenses. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. If the net investment in oil and gas properties exceeds an amount equal to the sum of:


(1	)	the standardized measure of discounted future net cash flows from proved reserves, and
(2	)	the lower of cost or fair market value of properties in process of development and unexplored acreage

The excess is charged to expense as additional depletion. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.

Aspen applies Statement of Financial Accounting Standard (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Under SFAS No. 144, long-lived assets and certain intangibles are reported at the lower of the carrying amount or their estimated recoverable amounts. Long-lived assets subject to the requirements of SFAS No. 144 are evaluated for possible impairment through review of undiscounted expected future cash flows. If the sum of undiscounted expected future cash flows is less than the carrying amount of the asset or if changes in facts and circumstances indicate, an impairment loss is recognized.

Asset Retirement Obligations

Aspen recognizes the future cost to plug and abandon gas wells over the estimated useful life of the wells in accordance with the provision of SFAS No. 143, “Asset Retirement Obligations.” SFAS No. 143 requires that Aspen record a liability for the present value of the asset retirement obligation with a corresponding increase to the carrying value of the related long-lived asset. The increase in the asset will be amortized over time and recognize accretion expense in connection with the discounted liability over the remaining life of the respective well. Any asset retirement costs capitalized pursuant to Statement 143 are subject to the full cost ceiling limitation under Rule 4-10(c)(4) of Regulation S-X. Aspen’s liability estimate is based on its historical experience in plugging and abandoning gas wells, estimated well lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. Revisions to the liability could occur due to changes in well lives, or if federal and state regulators enact new requirements on the plugging and abandonment of gas wells.

Income Taxes

Aspen computes income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”. SFAS No. 109 requires an assets and liability approach which results in the recognition of deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in Aspen’s financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, Aspen’s federal and state income tax returns are generally not filed before the financial statements are prepared; therefore Aspen estimates the tax basis of its assets and liabilities at the end of each calendar year as well as the effects of tax rate changes, tax credits, and tax credit carryforwards. A valuation allowance is recognized if it is determined that deferred tax assets may not be fully utilized in future periods. Adjustments related to differences between the estimates used and actual amounts reported are recorded in the period in which income tax returns are filed. These adjustments and changes in estimates of asset recovery could have an impact on results of operations. Due to uncertainties involved with tax matters, the future effective tax rate may vary significantly from the estimated current year effective tax rate.

Equity-Based Compensation

Aspen adopted SFAS No. 123(R) beginning July 1, 2006. Prior to July 1, 2006, Aspen accounted for these plans under the recognition and measurement provisions of Accounting Principles Board ("APB") Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, as permitted by Statement of Financial Accounting Standards("SFAS") No. 123, Accounting for Stock-Based Compensation. No stock-based employee compensation expense was recognized in Aspen's Consolidated Statement of Operations prior to July 1, 2006, as all options granted under Aspen 's stock-based compensation plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective July 1, 2006, Aspen adopted the fair value recognition provisions of SFAS No. 123 (R), Share Based Payment, using the modified-prospective transition method as described in SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, compensation cost recognized in the fiscal years ended June 30, 2008 and 2007 is the same as that which would have been recognized had the recognition provisions of Statement 123(R) been applied from its original effective date.

Investments in Debt and Equity Securities

Prior to the beginning of the current fiscal year, Aspen classified all investments as Trading Securities in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” These securities were marked to market each period with the realized and unrealized gain or loss recorded in the statement of operations. During the first quarter of fiscal year 2008, management reassessed the appropriateness of the classification of the securities held, and determined that due to the sufficiency of cash flows to finance current operations and budgeted expenditures, Aspen will hold investments until such time it determines there may be a need to sell those securities. As of July 1, 2007, management determined the securities are more appropriately classified as available for sale, and changes in the fair value of the securities are reported as a separate component of shareholders’ equity until realized. The securities were transferred from the trading category, and as such, the unrealized holding gain or loss at the date of the transfer has already been recognized in earnings and shall not be reversed. Aspen uses the specific identification method to determine the cost of securities sold.

Although Aspen’s production of natural gas remained approximately constant between fiscal 2007 (597,660 Mcf) and fiscal 2008 (595,621 Mcf), Aspen believes that its natural gas production is likely to increase during the 2009 fiscal year due to recent drilling successes. However, Aspen’s projections are subject to many factors and may not ultimately prove to be accurate. Total production for the year will depend on the number of wells successfully completed, the date they are put on line, their initial rate of production, and their production decline rates. During the last fiscal year,

	-	gas sales decreased approximately 8% from 631,557 MMbtu to 581,787 MMbtu;

	-	oil sales increased to 10,166 barrels due to full year results of the acquisition of operating interests in the Poplar fields in Montana; and

reserves have decreased approximately 5% to 3,298,744 net equivalent Mcf (MCFEQ) from 3,480,271 MCFEQ. Natural gas reserves reduced by approximately 20% from 2,701,201 Mcf (at June 30, 2007) to 2,150,734 Mcf (at June 30, 2008). The significant reduction of natural gas reserves resulted primarily from discoveries during the 2008 fiscal year (382,828 Mcf) being less than one-half of the discoveries achieved during the 2007 fiscal year (874,010 Mcf). If Aspen does not succeed in replacing its production with discoveries, its reserves will continue to decrease.

During fiscal 2008, the average price received for Aspen’s gas production increased approximately 8% from $7.00 per MMbtu to $7.58 per MMbtu. The average price received for oil increased almost 66% from $58.30 per barrel to $96.65 per barrel. Costs of production and accretion, depletion, depreciation, and amortization, increased 37%.

Over the past five years Aspen has been able to replace the majority of its produced reserves and maintain its yearly natural gas production through the drilling of new wells and the acquisition of producing properties which have offset the oil and gas Aspen produces although (as noted above) Aspen was not able to do so during its 2008 fiscal year due to significantly less discoveries than its natural gas discoveries during 2007. These 2008 additions resulted primarily from 7 newly drilled gas wells and the reactivation and improvement efforts on properties in which Aspen holds oil interests in Montana. Aspen’s oil reserves increased significantly during 2008 because of successful recompilations resulting in revisions of prior estimates, not as a result of any new discoveries. Overall, Aspen’s interest in net producing reserves of new wells replaced 64.3% of calculated total net gas sales in 2008. Management uses the measurement of Aspen’s produced reserves to help measure the success of its exploration and development activity. Where reserves are replaced in an amount greater than production, it is a sign that Aspen is continuing its exploration and development activity successfully. A one-year decline (as occurred during our fiscal 2008) or increase may not be important to investors, but seeing a decline or increase over a several year period is a trend worthy of noting, both internally by management and externally by investors.

At June 30, 2008, Aspen’s standardized measure of discounted future net cash flows from oil and gas operations was determined to be $10,269,000 as compared to $8,034,000 as at June 30, 2007. Aspen’s standardized measure increased during 2008 notwithstanding the reduction of Aspen’s reserves of oil (Bbl) and natural gas (Mcf) primarily because of the increased prices that we are receiving for Aspen’s production, offset in part by an increase in operating costs.

Quantitative and Qualitative Disclosure About Risk

Aspen’s ability to replace reserves, dissipated through production or recalculation, will depend largely on how successful Aspen’s drilling and acquisition efforts will be in the future. While Aspen cannot predict the future, and past results are not necessarily indicative of future success, Aspen’s historic success drilling ratio over the past seven years has been 84%. With the use of 3-D seismic and well control data, interpreted by Aspen’s geological and geophysical consultants, Aspen’s management feels they can manage dry hole risk adequately.

The prices that Aspen receives for the oil and natural gas (including natural gas liquids) produced are impacted by many factors that are outside of Aspen’s control. Historically, and as seen during calendar 2008, these commodity prices have been volatile and we expect them to remain volatile. Prices for oil and natural gas are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, the world political situation, basis differentials and other factors. As a result, Aspen cannot accurately predict future oil, natural gas and NGL (natural gas liquids) prices, and therefore, Aspen cannot determine what effect increases or decreases in production volumes will have on future revenues.

On regulatory and operational matters, Aspen actively manages its exploration and production activities. Aspen values sound stewardship and strong relationships with all stakeholders in conducting its business. Aspen attempts to stay abreast of emerging issues to effectively anticipate and manage potential impacts to its operations.

The average price we received during fiscal 2008 for Aspen’s natural gas was approximately $7.58 per MMBTU as compared to $6.63 per MMBTU during fiscal 2007. In order to reduce the risk of natural gas price fluctuations, Aspen has entered into a series of gas sales contracts with Enserco and Calpine.

Liquidity and Capital Resources:

Aspen has historically financed its operations with internally generated funds, limited borrowings from banks and third parties, and farmout arrangements, which permit third parties (including some related parties) to participate in its drilling prospects. During the year ended June 30, 2007, Aspen borrowed $600,000 to purchase an interest in the Poplar Field and became obligated for an additional $375,000 indebtedness as part of that purchase. During Aspen’s 2008 fiscal year, Aspen has also received approximately $20,000 from the sale of investment securities that Aspen owned, as compared to $600,000 in fiscal 2007.

Aspen’s principal uses of cash are for operating expenses, the acquisition, drilling, completion and production of prospects, the acquisition of producing properties, working capital, servicing debt and the payment of income taxes.

During the 2008 fiscal year, Aspen used approximately $2.5 million of cash in its operations, investing activities and financing activities, similar to those activities using $2.4 million during the same period of its 2007 fiscal year.

Aspen’s operating activities generated net cash of approximately $1.8 million from operations for the year ended June 30, 2008, as compared to approximately $2.5 million in cash generated from operating activities for the year ended June 30, 2007. This negative change of approximately $788,000 was due to a number of factors, including a reduction of Aspen’s net income of approximately $122,000 (as discussed below in results of operations), and a use of cash to retire current liabilities (which were about $5.3 million at June 30, 2007 as compared to $3.5 million at June 30, 2008). Aspen’s current liabilities decreased by about $1.8 million during the 2008 period as compared to a decrease in current liabilities of approximately $1.4 million during the 2007 period.

Aspen’s investing activities used cash to increase capitalized oil and gas costs of $3.9 million during the 2008 fiscal year as compared to $5.5 million in 2007. Investing activities during 2008 were for lease acquisition, seismic work, intangible drilling and well workovers and equipment. These expenditures are net of the sale of interests in wells to be drilled that will be charged to third party investors. In addition, Aspen invested $280,000 in municipal bonds in the current period.

Financing activities in the current year were solely to retire $275,000 of the $867,000 in long-term debt balance at June 30, 2007. Aspen did not declare or pay dividends in the current year; however, approximately $358,000 was paid in 2007.

Aspen’s working capital surplus (current assets less current liabilities) at June 30, 2008, was $1.3 million, which reflects a $722,000 decrease from our working capital at June 30, 2007. As detailed above, this decrease was due primarily to our negative cash flow of approximately $2.5 million for investing and operating activities.

Future Commitments

Aspen has a proposed drilling, completion and construction budget for the period July 2008 through June 2009. The budget includes drilling 2 gas wells in the Sacramento gas province of northern California. Aspen’s share of the estimated costs to complete this program is set forth in the following table.

					Completion &
			Drilling		Equipping
Area	Wells		Costs		Costs		Total

West Grimes Gas Field
Colusa County, CA		2	$	480,000	$	288,000	$	768,000

Total Expenditure		2	$	480,000	$	288,000	$	768,000

Aspen anticipates that its working capital and anticipated cash flow from operations and future successful drilling activities will be sufficient to finance our planned drilling and operating expenses and to pay our other obligations. As discussed herein, this is dependent, in part, on maintaining or increasing Aspen’s level of production and the national and world market maintaining its current prices for oil and gas production. Furthermore, Aspen expects to drill more than the two wells that are currently budgeted, but to date Aspen has not identified any drilling locations or timing for these anticipated additional wells.

If Aspen’s drilling efforts are successful, the anticipated increased cash flow from the new gas discoveries, in addition to Aspen’s existing cash flow, should be sufficient to fund its share of planned future completion and pipeline costs.

Results of Operations:

September 30, 2008 Compared to September 30, 2007

The following table sets forth certain items from Aspen’s Condensed Consolidated Statements of Operations as expressed as a percentage of total revenues, shown for the three months of fiscal 2009 and 2008:

	For the Three Months Ended
	September 30,			September 30,
	2008			2007

Total Revenues		100.0	%		100.0	%

Oil and Gas Production Costs		31.3	%		21.7	%

Gross Profit		68.7	%		78.3	%

Cost and Expenses
Depreciation and depletion		41.2	%		54.3	%
Selling, general and administrative		16.0	%		13.5	%

Total Cost and Expenses		88.4	%		67.8	%

Income from Operations		11.6	%		10.5	%

Other Income and Expenses		0.1	%		4.7	%

Income Before Income Taxes		11.7	%		15.2	%

Provision for Income Taxes		-2.8	%		-2.9	%

Net Income		8.9	%		12.3	%

To facilitate discussion of Aspen’s operating results for the three months ended September 30, 2008 and 2007, Aspen included the following selected data from its Condensed Consolidated Statements of Operations in its Quarterly Report on Form 10-Q for September 30, 2008:

	Comparison of the Fiscal Three
	Months Ended September 30,				Increase (Decrease)
	2008		2007		Amount			Percentage
Revenues:
Oil and gas sales	$	1,293,117	$	1,220,822	$	72,295			6	%

Cost and Expenses:
Oil and gas production		404,692		264,916		139,776			53	%
Depreciation and depletion		532,319		662,648		(130,329	)		-20	%
Selling, general and administrative		206,540		164,582		41,958			25	%

Total Costs and Expenses		1,143,551		1,092,146		51,405			5	%

Net Operating Income	$	149,566	$	128,676	$	20,890			16	%

Aspen experienced a positive increase in oil and gas revenues over the past year although its operations have been adversely affected by significantly increasing costs of production, as well as additional administrative, consulting, legal and accounting costs incurred. As noted, oil and gas prices are subject to national and international pressures, and Aspen has no control over those prices.

For the three months ended September 30, 2008, Aspen’s operations continued to be focused on the production of oil and gas in California and Montana. Aspen’s gas production decreased from 170,058 MMBTU sold during the first three months of September 30, 2007, to 119,724 MMBTU sold this quarter (a decrease of approximately 30%). Aspen’s production volume decreased so significantly because its producing wells followed expected decline curves (reducing production volume over time), but Aspen did not drill any additional wells to replace the reserves produced. Unless Aspen engages in further drilling operations, Aspen’s management anticipates that natural gas production volume will continue to decrease as the reserves in our existing wells are depleted.

Prices received during the first quarter of fiscal year 2009 increased approximately 34% over the same period compared to the same period in the last fiscal year as a result of international price increases that occurred during the period. As a result of the increase in prices during the first three months of Aspen’s 2009 fiscal year, and the production from our oil properties in Montana, Aspen’s revenues from oil and gas sales increased during the 2009 period by approximately $72,000 from approximately $1.22 million to approximately $1.29 million.

Oil and gas production costs increased approximately 53% in the three months ended September 30, 2008, as compared to the same period in 2007, from approximately $265,000 to almost $405,000. The increase can be attributed to the addition of gas wells, and Aspen’s percentage working interests in these wells were somewhat higher than the average of wells owned at September 30, 2007. Additionally, all of the costs for the service companies who perform work on Aspen's wells have increased dramatically.

Depletion, depreciation and amortization expense decreased 20%, from approximately $662,000 for the three months ended September 30, 2007 as compared to $532,000 during the 2008 period. This decrease was the result of decreased investments in oil and gas activities, which resulted in the lower total depletion taken. Depletion expense per equivalent unit of production (MCFe) was $3.75 and $3.53 for the three months ending September 30, 2008 and 2007, respectively.

When Aspen acts as operator for its producing wells, it receives management fees for these services, which serve to offset Aspen’s SG&A expenses. When comparing SG&A for the first quarter of 2009 and 2008, costs increased by about $29,000, or 9%, due primarily to consulting, accounting, and legal fees, while management fees decreased 9%. Management fees as a percentage of SG&A decreased 17% for the period ending September 30, 2008 compared to 2007.

A significant ratio presented is the percentage of management fees charged to operated wells versus Aspen’s general and administrative costs. This ratio coverage of general and administrative costs decreased from approximately 47.4% during the three months ended September 30, 2007 to approximately 39.6% at September 30, 2008.

	September 30,			September 30,
	2008			2007

Management fees	$	135,277		$	148,324
Selling, general and administrative (SG&A)		341,817			312,906
Management fees as a percentage of SG&A		39.6	%		47.4	%

Central to the issue of success of the three months operations ended September 30, 2008 is the discussion of changes in oil and gas sales, volumes of natural gas sold and the price received for those sales, as shown in the following table:

										Oil &
	Gas			MMBTU			Price/			NGL			Bbls			Price/
	Sales			Sold			MMBTU			Sales			Sold			Bbl

June 30, 2009
1st Quarter	$	996,710			119,724		$	8.33		$	296,407			2,903		$	102.10

Year to Date		996,710			119,724			8.33			296,407			2,903			102.10

June 30, 2008
1st Quarter		1,057,907			170,058			6.22			162,915			2,256			72.21
2nd Quarter		1,132,137			162,281			6.98			232,638			2,856			81.46
3rd Quarter		1,063,473			129,688			8.20			261,788			2,822			92.77
4th Quarter		1,154,356			119,760			9.64			325,153			2,232			145.68

June 30, 2008	$	4,407,873			581,787		$	7.58		$	982,494			10,166		$	96.65

2009 vs 2008
Amount	$	(61,197	)		(50,334	)	$	2.1		$	133,492			647		$	30
Percentage		-5.8	%		-29.6	%		33.8	%		81.9	%		28.7	%		41.4	%

Because of increased prices during the first quarter of fiscal year 2009 and notwithstanding a 30% reduction in natural gas production volumes, Aspen’s oil and gas revenues have shown an increase over the three months of fiscal 2009. As the table above notes, the volume of gas sold has decreased, but this decrease has been offset by a 33.8% increase in the price received per MMBTU of gas and 41.4% increase per barrel of oil. Prices have declined during the first part of the second quarter of Aspen’s fiscal 2009, and Aspen anticipate that, because it has not engaged in any additional drilling operations, production volume will likely decline during the next fiscal quarters. If that situation continues, Aspen anticipates that its revenues will decline during the remaining quarters of fiscal 2009.

Contractual Obligations

Aspen has entered into a series of gas sales contracts with Enserco and Calpine Producer Services, L.P. In each of the contracts, the purchasers were required to purchase the stated quantities at stated prices, less transportation and other expenses. The contracts contain monetary penalties for non-delivery of the gas.

Aspen expects to have sufficient gas available for delivery to Enserco from anticipated production from its California fields. Aspen’s sales of natural gas under the contracts qualify for the “Normal Purchases and Normal Sales” exception in paragraph 10(b) of FAS 133. The contract is a normal industry sales contract that provides for the sale of gas over a reasonable period of time in the normal course of business.

June 30, 2008 Compared to June 30, 2007

The following table sets forth certain items from Aspen ‘s Consolidated Statements of Operations as expressed as a percentage of total revenues, shown by year for fiscal 2008 and 2007:

	For the Year Ended
	June 30, 2008			June 30, 2007

Total Revenues		100.0	%		100.0	%

Oil and Gas Production Costs		27	%		18.9	%

Gross Profit		73	%		81.1	%

Cost and Expenses
Depreciation and depletion		45	%		45.7	%
Selling, general and administrative		12	%		19.3	%

Total Cost and Expenses		84	%		83.9	%

Income from Operations		16	%		16.1	%

Other Income and Expenses		1	%		18.8	%

Income Before Income Taxes		17	%		34.9	%

Provision for Income Taxes		-2	%		-13.9	%

Net Income		15	%		21.0	%

To facilitate discussion of Aspen’s operating results for the years ended June 30, 2008 and 2007, Aspen included in its analysis of results of operations the following selected data from its Consolidated Statements of Operations

	Comparison of the Fiscal
	Year Ended June 30,						Increase
	2008			2007			Amount			Percentage

Revenues:
Oil and gas sales	$	5,390,367		$	4,418,231		$	972,136			22	%

Cost and Expenses:
Oil and gas production		1,463,415			837,155			626,260			75	%
Depreciation and depletion		2,451,417			2,018,550			432,865			21	%
Selling, general and administrative		621,463			850,847			(229,384	)		-27	%

Total Costs and Expenses		4,536,295			3,706,552			829,741			22	%

Operating Income		854,074			711,679			142,395			20	%

Other Income (Expenses)		58,510			829,580			(771,072	)		-93	%

Income Tax Benefit (Provision)		(109,779	)		(615,990	)		506,211			-82	%

Net Income (Loss)	$	802,803		$	925,269		$	(122,466	)		-13	%

In general, Aspen’s operations during fiscal 2008 were adversely affected by significantly increasing costs of production and accretion, depletion, depreciation, and amortization, as well as additional administrative, consulting, legal, and accounting costs incurred as a result of Mr. Cohan’s stroke and disability to perform his duties as previously noted. Aspen’s income tax provision was significantly lower in the current year due to the carryback of a portion of our Net Operating Losses to prior years. As previously noted, oil and gas prices are subject to national and international pressures, and Aspen has no control over those prices.

For the fiscal year ended June 30, 2008, Aspen’s operations continued to be focused on the production of oil and gas in California and Montana. Aspen’s gas production decreased from 598,000 Mcf during the year ended June 30, 2007, to 596,000 Mcf during the fiscal year ended June 30, 2008 (a decrease of less than 1%). Oil production increased approximately 155% due to recompletion and improvement efforts in the recovery of oil in our Montana properties, and including the oil production from Aspen’s Montana properties in its financial information for a full year as compared to only six months during our 2007 fiscal year. As a result of the overall increase in production and increased prices during the 2008 fiscal year (14% increase per MMbtu and 57.6% increase per barrel of oil as compared to 2007), Aspen’s revenues from oil and gas sales increased during 2008 by approximately $972,000 from approximately $4.4 million (2007) to approximately $5.4 million (2008).

For the fiscal year ended June 30, 2008 oil and gas production costs increased approximately 75%, as compared to 2007, from approximately $837,000 to almost $1.5 million. The increase can be attributed to the addition of 7 gross operated gas wells, from 60 wells to 67 wells and our percentage working interests in these wells were somewhat higher than the average of wells owned at June 30, 2007. The increase was also due to the recompletion of oil wells in Montana. Equipment rental and water disposal fees increased due to the addition of compressors and increased water production in Aspen’s more mature wells. Additionally, all of the costs for the service companies who perform work on Aspen's wells increased dramatically during the past twelve months. Aspen is attempting to address these costs, but these costs are driven by market conditions and Aspen’s ability to control these costs is minimal. Generally the costs increase as prices received for oil and natural gas increase, but costs may increase more quickly than the prices received.

Depletion, depreciation and amortization expense increased 21%, from approximately $2 million for the year ended June 30, 2007 as compared to more than $2.4 million during 2008. DD&A expense per net equivalent Mcf produced increased from $3.25 to $3.75. This increase can be attributed to the continued level of investment in oil and gas-producing properties, without an immediate corresponding increase in proved reserves.

When Aspen acts as operator for its producing wells, it receives management fees for these services, which serve to offset its SG&A expenses. When comparing SG&A for 2008 and 2007, costs decreased by $135,000, or 10%, due primarily to decreases in accounting and audit fees and promotional, while management fees increased approximately $94,000, or 18%. As a result, management fees as a percentage of SG&A increased 31% for the period ending June 30, 2008 compared to 2007.

	2008 Fiscal			2007 Fiscal
	Year			Year

Management fees		607,269			512,923
Selling, general and administrative (SG&A)		1,228,732			1,363,770
Management fees as a percentage of SG&A		49.4	%		37.6	%

Central to the issue of success of the twelve months operations ended June 30, 2008 is the discussion of changes in oil and gas sales, volumes of natural gas sold and the price received for those sales. Aspen presented them here in tabular form:

	Gas			MMBT			Price/			Oil &			Bbls			Price/
	Sales			Sold			MMBT			Sales			Sold			Bbl

June 30, 2008	$	4,407,873			581,787		$	7.58		$	982,494			10,166		$	96.65

June 30, 2007	$	4,185,828			631,557		$	7.00		$	232,403			3,986		$	58.30

12 Month Change
2008 vs 2007
Amount	$	222,045			(49,770	)	$	0.6		$	750,091			6,180		$	38
Percentage		5.3	%		-7.9	%		8.2	%		322.8	%		155.0	%		65.8	%

Oil and gas revenue and volumes sold of Aspen’s product showed a general increase during fiscal 2008. As the table above notes, gas revenue increased approximately 5% when comparing the year ended June 30, 2008 and 2007, while oil revenue increased 323% due to the full year results of sales from the Poplar Field, acquired in the third quarter of our 2007 fiscal year. Gas volumes sold decreased approximately 8%, while the price received for Aspen’s product increased 8%. Oil and NGL volume increased 155%, due to the property acquisition, while the price per barrel increased 66%.

Aspen’s results of operations and net income (loss) before income taxes are presented in the following table:

Quarterly Financial Information (unaudited)

								Income (Loss)
						Income		Before Income Taxes
	Total		Operating			(Loss)		Per Share
	Revenues		Income¹			Income		Basic		Diluted
2008
lst Quarter	$	1,220,822	$	128,676		$	185,377	$	0.026	$	0.025
2nd Quarter		1,364,775		190,018			192,876		0.027		0.026
3rd Quarter		1,325,261		271,526			271,853		0.037		0.037
4th Quarter		1,479,509		263,852			262,476		0.036		0.036

Total		5,390,367		854,072			912,582		0.126		0.124

2007
lst Quarter	$	962,933	$	(105,987	)	$	185,219	$	0.026	$	0.025
2nd Quarter		1,053,839		264,970			507,576		0.071		0.069
3rd Quarter		1,344,790		437,471			629,345		0.088		0.086
4th Quarter		1,056,669		165,225			219,119		0.030		0.029

Total	$	4,418,231	$	761,679		$	1,541,259	$	0.215	$	0.209

1. Operating income is oil and gas sales less oil and gas production costs, depreciation, depletion and amortization, and selling, general and administrative expenses.

Income before taxes decreased from approximately $1.5 million for the year ended June 30, 2007 to $912,000 in 2008 primarily due to a 22% increase in operating expenses, and the reclassification of trading securities to available for sale. As of July 1, 2007, the unrealized gains or losses on securities are no longer included in Aspen’s results of operations.

Aspen’s future success in the oil and gas industry will depend on the cost of finding oil or gas reserves to replace its production, the volume of its production and the prices it receives for sale of our production. These factors are subject to all of the risks associated with operations in the oil and gas industry, many of which are beyond Aspen’s control.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following discussion of market risks was derived from Aspen’s Annual Report on Form 10-KSB for the fiscal year ended June 30, 2008.

As a crude oil and natural gas producer, Aspen’s revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Declines in commodity prices will materially adversely affect Aspen’s financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that Aspen can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond Aspen’s control, such as global, political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of Aspen’s production is sold at market prices. Generally, if the commodity indexes fall, the price that Aspen receives for its production will also decline. Therefore, the amount of revenue that it realizes is partially determined by factors beyond our control.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

The following description of changes in Aspen’s independent registered public accountants is ddrived from Aspen’s Annual Report on Form 10-KSB for the fiscal year ended June 30, 2008.

Dismissal of Hein & Associates, LLP. On March 1, 2007, the Aspen Board of Directors informed Hein that it had been dismissed as Aspen’s independent registered public accounting firm effective immediately. On the same date Aspen informed Gordon, Hughes & Banks, LLP that such firm was reappointed as Aspen’s independent registered accounting firm effective immediately.

During Aspen’s two most recent fiscal years and subsequently through the date of dismissal, there were no disagreements with Hein on any matter of accounting principles, practices, financial statement disclosure, or auditing scope or procedure which if not resolved to Hein’s satisfaction would have caused Hein to make reference to the subject matter of the disagreement in connection with its principal accounting report on the financial statements for our fiscal year ended June 30, 2007, or any subsequent report. However, as discussed in Aspen’s annual report for the year ended June 30, 2006, Hein advised Aspen that they were concerned about material weaknesses in Aspen’s disclosure controls based on several factors, including: corrections to Aspen’s financial statements and related disclosures that they proposed, the dual functions performed by Aspen’s president who is also Aspen’s chief financial officer; the lack of an audit committee; and the lack of sufficient professional accounting personnel at Aspen during the 2006 fiscal year. There is no legal requirement prohibiting Aspen’s president from serving as both principal executive and financial officer, and Aspen is not subject to a requirement to have an audit committee. As a result of the concerns expressed by Aspen’s auditors, Aspen’s president reached the conclusion that, in his opinion as of June 30, 2006, disclosure controls and procedures were not effective.

In reaching his conclusion Aspen’s president considered various mitigating factors, noting that formerly Aspen had one consultant serving Aspen on a part-time basis. During the last quarter of Aspen’s fiscal 2006, Aspen increased its accounting staff to three part-time consultants, including two certified public accountants. Aspen ‘s newly-enlarged staff worked together with Aspen during the last quarter of, and after the end of its fiscal year. Although the president identified material weaknesses as of June 30, 2006, the president observed the synergies and efficiencies developed by the new accounting team working together and with other Aspen personnel during the first quarter of the 2007 fiscal year in preparing Aspen’s financial statements for the 2006 fiscal year-end audit and concluded that the material weaknesses earlier identified had been eliminated during the first quarter of Aspen’s 2007 fiscal year. The president noted that these material weaknesses were addressed, not as a result of any changes in disclosure controls or procedures, but as a result of greater experience working together and with Aspen’s existing personnel. Consequently, Aspen’s president concluded that as of September 30, 2006 and subsequentlyits disclosure controls and procedures were effective.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT OF ASPEN

The following table sets forth as of July 31, 2008 the number and percentage of Aspen’s shares of $.005 par value common stock owned of record and beneficially owned by each person owning more than five percent of such common stock, and by each Director, and by all Officers and Directors as a group, as reported in the Annual Report on Form 10-KSB of Aspen for the year ended June 30, 2008. The percentages set forth in the table below are based on the total number of shares outstanding as set forth on the cover page to this annual report.

Stockholder (9)	Number		Percent

R.V. Bailey (1)		1,391,336		19.17	%

Robert A. Cohan (2)		742,737		10.23	%

Kevan B. Hensman (3)		28,120		0.39	%

Stockholder (9)	Number		Percent

All officers and directors as a group		3,245,536		36.8	%

The address for all of the above directors and executive officers is 2050 Oneida St., Suite 208, Denver, Colorado 80224.

(1) This number includes 1,241,776 shares of stock held of record in the name of R. V. Bailey, and 16,320 shares of record in the name of Mieko Nakamura Bailey, his spouse. Additionally, the number includes 32,000 shares of common stock Aspen issued to the Aspen Exploration Profit Sharing Plan for the benefit of R. V. Bailey as a corporation contribution to Mr. Bailey’s 401(k) account. The number of shares beneficially owned also includes stock options to purchase 101,240 shares of restricted common stock. However, the number of shares does not include stock options to purchase 133,333 shares that have not yet vested and will not vest until on or after September 30, 2009, to the extent earned.

(2) This number includes 527,644, shares of common stock. Additionally, Aspen issued 30,733 shares of common stock to the Aspen Exploration Profit Sharing Plan for the benefit of Robert A. Cohan as a corporation contribution to Mr. Cohan’s 401(k) account. The total number of shares beneficially owned by Mr. Cohan also includes stock options to purchase 184,360 shares of restricted common stock. However, the number of shares does not include stock options to purchase 200,000 shares that have not yet vested and will not vest until on or after September 30, 2009, to the extent earned.

(3) On September 11, 2006, upon being appointed to our board of directors Mr. Hensman was granted an option to purchase 10,000 shares of our common stock at $3.70 per share. These options vested immediately upon grant and are exercisable through September 11, 2011. Mr. Hensman also owns options exercisable to acquire 18,120 shares included in the above table. The table does not include options to acquire 66,667 shares, which will not vest until on or after September 30, 2009, to the extent earned.

Except with respect to the employment agreements between Aspen and R. V. Bailey and between Aspen and Robert Cohan, Aspen has indicated that it knows of no arrangement, the operation of which may, at a subsequent date, result in change in control of Aspen.

DESCRIPTION OF ROYALE CAPITAL STOCK

Royale is authorized to issue 10,000,000 shares of no par common stock and 10,000,000 shares of no par preferred stock, of which preferred shares 147,500 shares have been designated as Series AA preferred stock. As of September 30, 2008, 8,505,630 shares of common stock and 52,784 shares of Series AA preferred stock were issued and outstanding.

Common Stock

Each shareholder of the common stock is entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. In the election of directors, no shareholder shall be entitled to cumulate votes (i.e., case for any one or more candidates a number of votes greater than the number of shares) unless a shareholder has given notice of the intention to cumulate votes prior to the commencement of voting. If any shareholder has given notice of the intention to cumulate votes, then each shareholder has the right to give one candidate a number of votes equal to the number of directors to be elected multiplied by the number of directors to be elected multiplied by the number of shares held by the shareholder, or distributing such number of votes among as many candidates as the shareholder sees fit. Shareholders have no preemptive rights or other rights to subscribe for additional shares. There are no conversion rights, redemption rights, or sinking fund provisions with respect to the common stock. Shareholders are entitled to receive dividends, when declared by its board of directors, out of funds legally available therefore, subject to the restrictions set forth in the California Corporations Code. If Royale were to liquidate, dissolve, or wind up, the holders of the common stock would be entitled to receive, pro rata, the net assets of the company remaining after Royale satisfied its obligations with its creditors and preferred stockholders. Under Article IV of its Articles of Incorporation, the company has eliminated the potential liability for directors to it, and is also required to indemnify its directors against any liability for monetary damages, to the extent allowed by California law.¹

¹ The California Corporations Code allows corporations, including Royale, to eliminate or limit the liability of directors for money damages except to the extent that the acts of the director are in bad faith, constitute intentional or reckless misconduct, result in an improper personal benefit, or amount to an abdication of the director’s duty. The Corporations Code provisions do not affect the availability of equitable remedies against directors nor change the standard of duty to which directors are held. The Articles of Incorporation of Royale also provide that if California law is amended to provide additional indemnity or relief from liability to directors, such relief or indemnity shall automatically be applied for the benefit of the company’s directors.

Preferred Stock

Royale’s board of directors is authorized, without further action by stockholders, to issued preferred stock in one or more series and to fix the dividend rights, dividend rate, conversion rights, voting rights, rights and terms and conditions of redemption(including sinking fund provisions) preemptive rights, liabilities, liquidation preferences and other rights, qualifications, limitations and restrictions of any wholly unissued series of preferred stock, together with the designation of each series and the number of shares to constitute the series. The board of directors, without shareholder approval, can issue preferred stock with voting and conversion rights which could adversely affect the voting power of the holders of common stock.

Royale currently has one series of preferred stock issued and outstanding – Series AA. The holders of Series AA preferred stock are (i) entitled to receive a fixed liquidation value of $4.00 per share; (ii) have the right to convert to common stock at a conversion exchange rate of one share of common stock for each two shares of Series AA preferred stock; (iii) have voting rights equal to the number of shares into which they are convertible, and shall be voted with the common stock except as otherwise required by law; and (iv) were paid a one-time dividend equal to $0.40 per share one year after the date of issuance. Royale is also entitled to call the Series AA preferred stock at any time after six months from the date of issuance, or from time to time thereafter, upon proper notice, at $4.00 per share.

COMPARISON OF STOCKHOLDERS’ RIGHTS.

The following is a summary of the material differences between (a) the current rights of Royale stockholders under Royale’s articles of incorporation and bylaws and (b) the current rights of Aspen stockholders under Aspen’s certificate of incorporation and bylaws.

The following summary is not a complete statement of the rights of stockholders of the two companies or a complete description of the specific provisions referred to below. This summary is qualified by reference to California and Delaware law and Royale’s and Aspen’s constituent documents.

Authorized Capital Stock

Royale - The total number of shares of no par common stock which this corporation is authorized to issue is 10,000,000. As of September 30, 2008, 8,538,717 shares of common stock were issued and outstanding.

Aspen - The authorized capital stock of this corporation consists of 50,000,000 shares of common stock with $0.005 par value per share.

Dividend Policy

Royale– For purposes of determining the shareholders entitled to receive payment of dividends the Board of Directors may fix, in advance, a record date, which shall not be more than 60 days prior to any such action, and in such case only shareholders of record on the date so fixed are entitled to receive the dividend, notwithstanding any transfer of any shares on the books of the corporation after the record date fixed as aforesaid, except as otherwise provided in the California General Corporation Law. If the Board of Directors does not so fix a record date, the record date for determining shareholders for any such purpose shall be at the close of business on the day on which the Board adopts the resolution relating thereto, or the sixtieth (60th) day prior to the date of such action, whichever is later.

Aspen - In order that the Corporation may determine the stockholders entitled to receive payment of any dividend, the Board of Directors may fix, in advance, a record date, which shall not be more than 60 or less than 10 days before the date of such meeting, nor more than 60 days prior to any other action. If no record date is fixed, the record date shall be at the close of business on the day on which the Board of Directors adopts the resolution relating to the payment of any dividend.

Voting

Royale - The shareholders entitled to vote at any meeting of shareholders shall be determined in accordance with the provisions of Section 2.11, subject to the provisions of Sections 702 to 704, inclusive, of the Corporations Code of California (relating to voting shares held by a fiduciary, in the name of a corporation or in joint ownership). Such vote may be by voice vote or by ballot; provided, however, that all elections for directors must be by ballot upon demand by a shareholder at any election and before the voting begins. Any shareholder entitled to vote on any matter (other than the election of directors) may vote part of the shares in favor of the proposal and refrain from voting the remaining shares or vote them against the proposal, but, if the shareholder fails to specify the number of shares such shareholder is voting affirmatively, it will be conclusively presumed that the shareholder’s approving vote is with respect to all shares such shareholder is entitled to vote. If a quorum is present, the affirmative vote of the majority of the shares represented at the meeting and voting on any matter (other than the election of directors), provided that the shares voting affirmatively must also constitute at least a majority of the required quorum, shall be the act of the shareholders, unless the vote of a greater number or voting by classes is required by the California General Corporation Law or the articles of incorporation.

At a shareholders’ meeting involving the election of directors, no shareholder shall be entitled to cumulate votes (i.e., cast for any candidate a number of votes greater than the number of the shareholder’s shares) unless such candidate or candidates’ names have been placed in nomination prior to commencement of the voting and a shareholder has given notice prior to commencement of the voting of the shareholder’s intention to cumulate votes. If any shareholder has given such notice, then every shareholder entitled to vote may cumulate such shareholder’s votes for candidates in nomination and give one candidate a number of votes equal to the number of directors to be elected multiplied by the number of votes to which such shareholder’s shares are entitled, or distribute the shareholder’s votes on the same principle among any or all of the candidates, as the shareholder thinks fit. The candidates receiving the highest number of votes, up to the number of directors to be elected, shall be elected.

Aspen– Each stockholder at every meeting of the stockholders is entitled to one vote for each share of capital stock held by him. Each stockholder entitled to vote at a meeting of stockholders or to express consent or dissent to corporate action in writing without a meeting may authorize another person or persons to act for him by proxy, but no such proxy will be voted/acted upon after 10 months from its date. Each matter, other than election of directors, properly presented to meeting will be decided by a majority of votes. Directors are to be elected by a plurality vote. Election of directors and the vote on any other matter shall be by written ballot only if so ordered by the chairman of the meeting, or if so requested by any stockholder present, or represented by proxy, at the meeting entitled to vote in such election or on such matter, as the case may be.

Number of Directors

Royale - The number of directors which shall constitute the whole Board of Directors shall be not less than three (3) nor more than nine (9); the exact number of directors to be determined from time to time solely by resolution adopted by the affirmative vote of a majority of the directors or by the vote or written consent of a majority of shareholders. The directors of the Corporation need not be residents of Delaware and shall not be required to hold shares of the Corporation’s capital stock. Royale’s Board of Directors currently consists of eight directors.

As required by NASDAQ listing requirements, a majority of the members of the Royale Board of Directors are independent directors as that term is defined by NASDAQ rules. Also in compliance with NASDAQ listing requirements, Royale has an audit committee, a nominations committee and a compensation committee, all of which are composed entirely of independent directors.

Aspen - The number of directors that shall constitute the whole Board shall be determined by action of the Board of Directors taken by the affirmative vote of a majority of the whole Board. Aspen’s Board of Directors currently consists of three directors, none of whom are independent directors. Aspen has no board committees composed of independent directors.

Term of Directors

Royale - Directors shall be elected at each annual meeting of the shareholders to hold office until the next annual meeting. Each director, including a director elected to fill a vacancy, shall hold office until the expiration of the term for which elected and until a successor has been elected and qualified.

Aspen– Directors elected at the annual meeting of stockholders hold office until the next annual meeting of stockholders and until their respective successors are elected and qualified.

Removal of Directors

Royale– Subject to the rights, if any, of an officer under any contract of employment, any officer may be removed, either with or without cause, by the Board of Directors, at any regular or special meeting thereof, or, except in case of an officer chosen by the Board of Directors, by any officer upon whom such power of removal may be conferred by the Board of Directors.

Aspen– Any one or more directors may be removed, with or without cause, by vote or written consent of the holders of a majority of the issued and outstanding shares of stock of the Corporation entitled to vote for the election of directors.

Vacancies on the Board

Royale - A vacancy or vacancies in the Board of Directors shall be deemed to exist in the case of the death, resignation or removal of any director, or if the Board of Directors by resolution declares vacant the office of a director who has been declared of unsound mind by an order of court or convicted of a felony, or if the authorized number of directors be increased, or if the shareholders fail, at any meeting of shareholders at which any director or directors are elected, to elect the full authorized number of directors to be voted for at that meeting.

Aspen– Vacancies and newly elected dictatorships resulting from any increase in the authorized number of directors may be filled by a majority of the directors then in office, though less than a quorum, or by the sole remaining director, and the directors so chosen will hold office until the next annual meeting of stockholders and until their respective successors are elected and qualified.

Annual Stockholders Meeting

Royale - Meetings of shareholders shall be held at any place within or outside the State of California designated by the Board of Directors. In the absence of any such designation, shareholders’ meetings shall be held at the principal executive office of the corporation. The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors. At each annual meeting directors shall be elected and any other proper business may be transacted.

Aspen– An annual meeting of stockholders to elect directors and transact such other business as may be properly presented shall be held at such place as the Board of Directors may set each year. Aspen’s Annual Report on Form 10-KSB discloses that Aspen has not held an annual meeting of shareholders since 1994.

Special Stockholders Meetings

Royale - A special meeting of the shareholders may be called at any time by the Board of Directors, or by the Chairman of the Board, or by the President, or by one or more shareholders holding shares in the aggregate entitled to cast not less than 25% of the votes at any such meeting. If a special meeting is called by any person or persons other than the Board of Directors, the request shall be in writing, specifying the time of such meeting and the general nature of the business proposed to be transacted, and shall be delivered personally or sent by registered mail or by telegraphic or other facsimile transmission to the Chairman of the Board, the President, any Vice President or the Secretary of the corporation. The officer receiving such request forthwith shall cause notice to be given to the shareholders entitled to vote, in accordance with the provisions of Section 2.11 of the Bylaws, that a meeting will be held at the time requested by the person or persons calling the meeting, not less than thirty-five (35) nor more than sixty (60) days after the receipt of the request. If the notice is not given within twenty (20) days after receipt of the request, the person or persons requesting the meeting may give the notice.

Aspen– A special meeting of stockholders may be called at any time by the Board of Directors, its Chairman, the Executive Committee or the President. The President or Secretary shall call a special meting upon receipt of a written request to do so specifying the matter(s) proposed to be presented at the meeting and signed by holders of record of at least 10% of the shares of stock entitled to vote on such a matter if the meeting were held on the day such request was received and the record date for such meeting were the close of business on the preceding day. The shareholders requesting such action must also provide all of the information that would be required to be included in a proxy statement under Section 14(a) of the Securities Exchange Act of 1934, as amended. Any special meeting may be held at any time, within or without the State of Delaware, as determined by the person calling the meeting and as shall be stated in the notice of such meeting.

Quorum for Stockholders Meetings

Royale - The presence in person or by proxy of the holders of a majority of the shares entitled to vote at any meeting of shareholders shall constitute a quorum for the transaction of business. The shareholders present at a duly called or held meeting at which a quorum is present may continue to do business until adjournment, notwithstanding the withdrawal of enough shareholders to leave less than a quorum, if any action taken (other than adjournment) is approved by at least a majority of the shares required to constitute a quorum.

Aspen - A majority of the number of directors at any time constituting the Board of Directors shall constitute a quorum for the transaction of business, and the act of a majority of the directors present at a meeting at which a quorum is present shall be the act of the Board of Directors.

Advance Notice Procedures for a Stockholder Proposal

Royale - All notices of meetings of shareholders shall be sent or otherwise given not less than ten (10) nor more than sixty (60) days before the date of the meeting being noticed. The notice shall specify the place, date and hour of the meeting and (i) in the case of a special meeting, the general nature of the business to be transacted, or (ii) in the case of the annual meeting those matters which the Board of Directors, at the time of giving the notice, intends to present for action by the shareholders. The notice of any meeting at which directors are to be elected shall include the name of any nominee or nominees which, at the time of the notice, management intends to present for election.

If action is proposed to be taken at any meeting for approval of (i) a contract or transaction in which a director has a direct or indirect financial interest, pursuant to Section 310 of the Corporations Code of California, (ii) an amendment of the articles of incorporation, pursuant to Section 902 of such Code, (iii) a reorganization of the corporation, pursuant to Section 1201 of such Code, (iv) a voluntary dissolution of the corporation, pursuant to Section 1900 of such Code, or (v) a distribution in dissolution other than in accordance with the rights of outstanding preferred shares pursuant to Section 2007 of such Code, the notice shall also state the general nature of such proposal.

Aspen– For each meeting of stockholders written notice shall be given stating the place, date and hour and, in case of a special meeting, the purpose(s) for which the meeting is called. Except as otherwise provided by Delaware law, the written notice of any meeting shall be given not less than 10 nor more than 60 days before the date of the meeting to each stockholder entitled to such at such meeting. If mailed, notice shall be deemed to be given when deposited in U.S. mail, postage prepaid, directed to the stockholder at his address as it appears on the records of the Corporation.

Stockholder Action by Written Consent

Royale - Any action which may be taken at any annual or special meeting of shareholders may be taken without a meeting and without prior notice, if a consent in writing, setting forth the action so taken, is signed by the holders of outstanding shares having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted. All such consents shall be filed with the Secretary of the corporation and shall be maintained in the corporate records. Any shareholder giving a written consent may revoke the consent by a writing received by the Secretary of the corporation prior to the time that written consents of the number of shares required to authorize the proposed action have been filed with the Secretary.

Aspen - Any action that may be taken at any annual or special meeting of stockholders may be taken without a meeting, without prior notice and without a vote, if a consent in writing, setting forth the action so taken, shall be signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted. Notice of the taking of such action shall be given promptly to each stockholder that would have been entitled to vote thereon at a meeting of stockholders, and that did not consent thereto in writing.

Amendment of Governing Documents

Royale - New bylaws may be adopted or these bylaws may be amended or repealed by the vote or written consent of holders of a majority of the outstanding shares entitled to vote; provided, however, that if the articles of incorporation of the corporation set forth the number of authorized directors of the corporation, the authorized number of directors may be changed only by an amendment of the articles of incorporation. Under California law, amendments to Royale’s Articles of Incorporation may be adopted if approved by the board and approved by the outstanding shares, either before or after the approval by the board.

Aspen - The bylaws may be made, altered or repealed at any meeting of stockholders; or at any meeting of the Board of Directors by a majority vote of the whole Board. The provisions of Article V (Initial Directors) of Aspen’s Certificate of Incorporation shall not be modified, revised, altered, amended, repealed or rescinded, in whole or in part, except by the affirmative vote of not less than two-thirds of all of the shares of stock outstanding and entitled to vote thereon and two-thirds of the outstanding stock of each class entitled to vote thereon as a class.

Exculpation of Directors

Royale– Liability of the directors of this corporation for monetary damage shall be eliminated to the fullest extent permissible under California law. This corporation is also authorized, to the fullest extent possible under California law, to indemnify its agents (as defined in Section 317 of the California Corporations Code), whether by by-law, agreement or otherwise, for breach of duty to this corporation and its shareholders in excess of that expressly permitted by Section 317 and to advance defense expenses to its agents in connection with such matters as they are incurred, subject to the limits on such excess indemnification set forth in Section 204 of the California Corporations Code.

Aspen - To the fullest extent permitted by the Delaware General Corporation Law, as the same exists or may hereafter be amended, a director of this Corporation shall not be liable to the Corporation or its stockholders for monetary damages for breach of fiduciary duty as a director. Under Delaware law, Aspen cannot eliminate director liability for (i) any breach of a director’s duty of loyalty to the company or its stockholders, (ii) acts or omissions that are not in good faith or which involve intentional misconduct or a knowing violation of the law, (iii) violations of Section 174 of the DGCL (relating to unlawful payment of dividends or unlawful stock purchases or redemptions) or (iv) any transaction from which a director derives an improper personal benefit.

Indemnification of Directors and Officers

Royale - The corporation shall, to the maximum extent permitted by the California General Corporation Law, indemnify each of its directors and officers against expenses, judgments, fines, settlements and other amounts actually and reasonably incurred in connection with any proceeding arising by reason of the fact any such person is or was a director or officer of the corporation and shall advance to such director or officer expenses incurred in defending any such proceeding to the maximum extent permitted by such law. For purposes of this Section 0, a "director" or "officer" of the corporation includes any person who is or was a director or officer of the corporation, or is or was serving at the request of the corporation as a director or officer of another corporation, or other enterprise, or was a director or officer of a corporation which was a predecessor corporation of the corporation or of another enterprise at the request of such predecessor corporation. The Board of Directors may in its discretion provide by resolution for such indemnification of, or advance of expenses to, other agents of the corporation, and likewise may refuse to provide for such indemnification or advance of expenses except to the extent such indemnification is mandatory under the California General Corporation law.

Aspen– Aspen provide for indemnification of any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, by reason of the fact that he is or was a director, officer, employee or agent, or is was serving at the request of Aspen as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, or other enterprise, against expenses, judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding, if he acted in good faith, and in manner he reasonably believed to be in, or not opposed to, the best interests of Aspen and had no reasonable cause to believe his conduct was unlawful.

No indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable for negligence or misconduct in the performance of his duties to the Corporation, unless and only to the extent, that the Court of Chancery of the State of Delaware or the court in which such action or suit was brought shall determine upon application, that despite the adjudication of liability, but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses as the Court of Chancery of the State of Delaware or such other court shall deem proper.

Business Combination Statute

Aspen - Under Section 203 of the Delaware General Corporation Law, some business combinations by Delaware corporations with interested stockholders are subject to a three-year moratorium unless specified conditions are met. Section 203 prohibits a Delaware corporation from engaging in a business combination with an interested stockholder for three years following the date that such person becomes an interested stockholder. With some exceptions, an interested stockholder is generally a person or group who or which owns 15% or more of the corporation's outstanding voting stock, including any rights to acquire stock pursuant to an option, warrant, agreement, arrangement or understanding, or upon the exercise of conversion or exchange rights, and stock with respect to which the person has voting rights only, or is an affiliate or associate of the corporation and was the owner of 15% or more of such voting stock at any time within the previous three years.

A Delaware corporation may opt out of this provision through an amendment to its certificate of incorporation or bylaws adopted by a majority of the outstanding voting shares, provided that, in most cases, such an amendment will not become effective until 12 months after its adoption and will not apply to any person who became an interested stockholder on or prior to its adoption. To Royale’s knowledge, Aspen has not adopted any such amendment.

Royale– California does not have a comparable statute.

LEGAL REQUIREMENTS CONCERNING THE OFFER

This offer is being made solely by this prospectus and the accompanying letter of transmittal. The offer is being made to all holders of shares of Aspen common stock. Royale is not aware of any jurisdiction where making the offer or tendering shares of Aspen in response to the offer would violate the laws of the jurisdiction. If Royale becomes aware of any jurisdiction in which making the offer or tendering shares of Aspen in response could violate applicable law, Royale will make a good faith effort to comply with any such law. If, after such good faith effort, Royale cannot comply with any such law, the offer will not be made to (nor any tenders be accepted from or on behalf of) the holders of shares of Aspen common stock in such jurisdiction. In any jurisdiction where the securities, blue sky or other laws require the offer to be made by a licensed broker or dealer, the offer shall be deemed to be made on behalf of Royale by one or more registered brokers or dealers licensed under the laws of such jurisdiction.

EXPERTS

Accounting Matters

Our financial statements as of December 31, 2007 and 2006, and for the years then ended, have been audited by Padgett, Stratemann & Co., L.L.P., independent public accountants, as indicated in their report contained in our Form 10-K for the year ended December 31, 2007, which is incorporated by reference in this prospectus.

Engineering Matters

Information related to the estimated proved reserves attributable to certain oil and gas properties of Royale as of December 31, 2007, and estimates of future net cash flows and present value of the reserves have been incorporated by reference in Royale's Annual Report on Form 10-K for the year ended December 31, 2007, which is incorporated herein by reference, in reliance on the reserve report, dated February 7, 2008, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers.

Legal Matters

The validity of the common shares offered pursuant to this prospectus will be passed on by Strasburger & Price, L.L.P., San Antonio, Texas.

INFORMATION INCORPORATED BY REFERENCE

The SEC allows us to "incorporate by reference" the information we file with them, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is an important part of this prospectus, and information that we file later with the SEC will automatically update and supersede previously filed information, including information contained in this document. We incorporate by reference the documents listed below (SEC file No. 0-22750) and any future filings we will make with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 until we have sold all shares offered by this Prospectus or until this offering is otherwise completed:

-	Our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on April 1, 2008.
-	Our Quarterly Report on Form 10-Q for the period ended September 30, 2008, filed with the SEC on November 3, 2008.
-	Our Current Reports on Form 8-K dated June 10, 2008 (filed June 12, 2008), dated August 30, 2008 (filed September 3, 2008), and dated October 17, 2008 (filed October 23, 2008)
-	Our Definitive Proxy Statement for our 2008 Annual Meeting of Shareholders, filed with the SEC on May 2, 2008

You may request free copies of these filings by writing or telephoning us at the following address:

Royale Energy, Inc.

7676 Hazard Centre Drive

Suite 1500

San Diego, CA 92108

619-881-2800

E-mail: www.royl.com

INDEX TO FINANCIAL STATEMENTS

		Page
Financial Statements of Royale Energy, Inc.
	Report of Padgett, Stratemann & Co., LLP, Independent Auditors
	Balance Sheets at December 31, 2007 and 2006
	Statements of Operations for the Years Ended December 31, 2007, 2006, and 2005
	Statements of Stockholders' Equity for the Years Ended December 31, 2007, 2006, and 2005
	Statements of Cash Flows for the Years Ended December 31, 2007, 2006, and 2005
	Notes to the Financial Statements
	Supplemental Information about Oil and Gas Producing Activities (Unaudited)

	Financial statement schedules have been omitted since they are either not required, are not applicable, or the required information is shown in the financial statements and related notes.

Unaudited Financial Statements of Royale Energy, Inc., for the Quarterly Periods Ended September 30, 2008 and 2007
	Balance Sheets at September 30, 2008 (unaudited) and December 31, 2007
	Statements of Operations for the Three and Nine Months Ended September 30, 2008 and 2007 (unaudited)
	Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007 (unaudited)
	Notes to Unaudited Financial Statements

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

of Royale Energy, Inc.

We have audited the accompanying balance sheets of Royale Energy, Inc. (the “Company”) as of December 31, 2007 and December 31, 2006, and the related statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Royale Energy, Inc. as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.

PADGETT, STRATEMANN & COMPANY, L.L.P.

Austin, Texas

March 29, 2008

F-2

ROYALE ENERGY, INC

BALANCE SHEETS

DECEMBER 31, 2007 AND 2006

ASSETS

	2007		2006

Current Assets
Cash and Cash Equivalents	$	3,848,968	$	7,377,604
Accounts Receivable, net		4,090,341		2,906,290
Prepaid Expenses		673,453		2,301,267
Deferred Tax Asset		217,586		195,615
Inventory		344,339		401,521

Total Current Assets		9,174,687		13,182,297

Investments		6,946		6,946

Oil And Gas Properties (Successful Efforts Basis)
Equipment and Fixtures		23,389,741		20,525,960

Total Assets	$	32,571,374	$	33,715,203

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

F-3

ROYALE ENERGY, INC.

BALANCE SHEETS

DECEMBER 31, 2007 AND 2006

LIABILITIES AND STOCKHOLDERS' EQUITY
	2007			2006
Current Liabilities:
Accounts Payable and Accrued Expenses	$	10,080,034		$	7,158,612
Current Portion of Long-Term Debt		0			233,045
Deferred Revenue from Turnkey Drilling		3,947,097			5,018,261

Total Current Liabilities		14,021,131			12,409,918

Noncurrent Liabilities:
Asset Retirement Obligation		402,278			273,049
Deferred Tax Liability		581,181			1,673,922
Long-Term Debt, Net of Current Portion		5,175,974			3,810,000

Total Noncurrent Liabilities		6,159,433			5,756,971

Total Liabilities		20,186,564			18,166,889


Stockholders' Equity

Common Stock, No Par Value, 10,000,000 Shares Authorized; 7,951,746 and 7,951,748 Shares Issued; 7,918,659 and 7,916,408 Outstanding, Respectively		19,511,963			19,511,963
Convertible Preferred Stock, Series AA, No Par Value,
147,500 Shares Authorized; 57,416 and 57,416
Shares Issued and Outstanding, Respectively		167,979			167,979
Accumulated (Deficit)		(7,140,695	)		(3,964,439	)

Total Paid in Capital and Accumulated Deficit		12,539,247			15,715,503

Less Cost of Treasury Stock, 33,087 and 35,340 Shares		(181,012	)		(192,052	)

Paid in Capital, Treasury Stock		26,575			24,863

Total Stockholders' Equity		12,384,810			15,548,314

Total Liabilities and Stockholders' Equity	$	32,571,374		$	33,715,203

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

F-4

ROYALE ENERGY, INC.

STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005

	2007			2006			2005
Revenues
Sale of Oil and Gas	$	6,110,092		$	7,965,633		$	11,228,537
Turnkey Drilling		9,408,103			15,711,550			13,066,800
Supervisory Fees and Other		1,039,204			1,218,860			1,348,041

Total Revenues	$	16,557,399		$	24,896,043		$	25,643,378

Costs and Expenses:
General and Administrative		4,712,624			5,129,074			4,877,168
Geological and Geophysical Expenses		423,459			400,306			381,790
Turnkey Drilling Development		4,977,811			9,628,394			8,111,248
Lease Operating		2,116,977			1,968,269			2,751,441
Lease Impairment		2,106,670			6,191,417			742,642
Legal and Accounting		928,628			397,575			236,199
Marketing		1,455,296			1,799,088			2,222,859
Depreciation, Depletion and Amortization		3,585,682			5,833,904			4,062,587

Total Costs and Expenses		20,307,147		$	31,348,027		$	23,385,934

Gain (Loss) on Sale of Assets		(135,396	)		3,263,368			-

Income (Loss) from Operations		(3,885,144	)	$	(3,188,616	)	$	2,257,444

Other Expense:
Interest Expense		152,547			523,139			444,271

Income (Loss) Before Income Tax Expense		(4,037,691	)		(3,711,755	)		1,813,173

Income Tax Expense (Benefit)		(1,258,484	)		(1,062,054	)		627,270

Net Income (Loss)	$	(2,779,207	)	$	(2,649,701	)	$	1,185,903

Basic Earnings Per Share:
Net Income (Loss) Available To Common Stock	$	(0.35	)	$	(0.33	)	$	0.15

Diluted Earnings (Loss) Per Share	$	(0.35	)	$	(0.33	)	$	0.15

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

F-5

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005

	Common Stock						Preferred Stock Series AA
	Shares						Shares
	Issued			Amount			Outstanding		Amount
Balance at January 1, 2005		7,859,223		$	19,591,039			57,416	$	167,979

Stock Options Repurchased		-			(188,912	)		-		-

Stock Options Exercised		89,465			98,247			-		-

Stock Award		-			-			-		-

Net Income (Loss) for the Year		-			-			-		-

Balance at December 31, 2005		7,948,688		$	19,500,374			57,416	$	167,979

Conversion of Preferred A		3,060		$	11,589			-		-

Stock Acquisition In Lieu Of Receivables		-			-			-		-

Stock Award		-			-			-		-

Net Income (Loss) for the Year		-			-			-		-

Balance at December 31, 2006		7,951,748		$	19,511,963			57,416	$	167,979

Stock Options Exercised Adjustment		(2	)		-			-		-

Cash Dividend $0.05 Per Share		-			-			-		-

Stock Award		-			-			-		-

Net Income (Loss) for the Year		-			-			-		-

Balance at December 31, 2007		7,951,746		$	19,511,963			57,416	$	167,979

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

F-6

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005

	Preferred Stock Series A
	Shares						Accumulated
	Outstanding			Amount			Deficit

Balance at January 1, 2005		6,122		$	11,589		$	(2,500,641	)

Stock Options Repurchased		-			-			-

Stock Options Exercised		-			-			-

Stock Award		-			-			-

Net Income (Loss) for the Year		-			-			1,185,903

Balance at December 31, 2005		6,122		$	11,589		$	(1,314,738	)

Conversion of Preferred A		(6,122	)	$	(11,589	)		-

Stock Acquisition In Lieu Of Receivables		-			-			-

Stock Award		-			-			-

Net Income (Loss) for the Year		-			-		$	(2,649,701	)

Balance at December 31, 2006		-		$	-		$	(3,964,439	)

Stock Options Exercised Adjustment		-			-			-

Cash Dividend $0.05 Per Share		-			-			(397,049	)

Stock Award		-			-			-

Net Income (Loss) for the Year		-			-		$	(2,779,207	)

Balance at December 31, 2007		-		$	-		$	(7,140,695	)

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

F-7

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006, AND 2005

	Treasury Stock						Paid in
	Shares						Capital
	Acquired			Amount			Treasury Stock		Total

Balance at January 1, 2005		20,000		$	(97,906	)	$	16,761	$	17,188,821

Stock Options Repurchased		-			-			-		(188,912	)

Stock Options Exercised		-			-			-		98,247

Stock Award		(6,048	)		29,635			4,596		34,231

Net Income (Loss) for the Year		-			-			-		1,185,903

Balance at December 31, 2005		13,952		$	(68,271	)	$	21,357	$	18,318,290

Conversion of Preferred A		-			-			-		-

Stock Acquisition In Lieu Of Receivables		26,000		$	(146,380	)		-	$	(146,380	)

Stock Award		(4,612	)		22,599			3,506	$	26,105

Net Income (Loss) for the Year		-			-			-	$	(2,649,701	)

Balance at December 31, 2006		35,340		$	(192,052	)	$	24,863	$	15,548,314

Stock Options Exercised Adjustment		-			-			-		-

Cash Dividend $0.05 Per Share		-			-			-		(397,049	)

Stock Award		(2,253	)		11,040			1,712		12,752

Net Income (Loss) for the Year		-			-			-		(2,779,207	)

Balance at December 31, 2007		33,087		$	(181,012	)	$	26,575	$	12,384,810

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

F-8

ROYALE ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2006

	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(2,779,207	)	$	(2,649,701	)	$	1,185,903
Adjustments to Reconcile Net Income to Net
Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		3,585,682			5,833,904			4,062,587
Lease Impairment		2,106,670			6,191,417			742,642
(Gain) Loss on Sale of Assets		135,396			(3,263,368	)		-
Bad Debt Expense		262,532			582,204			401,691
Compensation Expense – Stock Grant		12,752			26,105			34,231
(Increase) Decrease in:
Accounts Receivable		(1,446,283	)		586,727			(719,351	)
Prepaid Expenses and Other Assets		1,684,996			(20,645	)		1,997,055
Increase (Decrease) in:
Accounts Payable and accrued Expenses		3,050,651			(189,127	)		(2,273,741	)
Deferred Revenues – DWI		(1,071,164	)		(1,471,850	)		1,210,694
Deferred Income Taxes		(1,114,712	)		(2,219,273	)		(246,269	)

Net Cash Provided by Operating Activities		4,427,012			3,406,393			6,395,442

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Oil and Gas Properties and
Other Capital Expenditures		(8,835,180	)		(3,091,316	)		(9,888,809	)
Proceeds from Sale of Assets		143,652			5,024,054			-

Net Cash Provided (Used) by Investing Activities		(8,691,528	)		1,932,738			(9,888,809	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt		6,150,000			2,115,000			13,777,500
Principal Payments on Lon-Term Debt		(5,017,071	)		(4,793,299	)		(13,103,741	)
Dividends Paid		(397,049	)		-			-
Exercise of Options for Cash		-			-			98,247
Repurchase of Stock Options		-			-			(188,912	)

Net Cash Provided (Used) by Financing Activities		735,880			(2,678,299	)		583,094

Net Increase (Decrease in Cash and Cash
Equivalents		(3,528,636	)		2,660,832			(2,910,273	)

Cash & Cash Equivalents at Beginning of Year		7,377,604			4,716,772			7,627,045

Cash & Cash Equivalents at End of Year	$	3,848,968		$	7,377,604		$	4,716,772

Cash & Cash Equivalents

SUPPLEMENTAL DISCLOSURES OF CASH
FLOWS INFORMATION:
Cash Paid for Interest	$	173,028		$	529,940		$	290,367

Cash Paid for Taxes	$	579,080		$	259,006		$	369,063

SUPPLEMENTAL DISCLOSURES OF NON-CASH
INVESTING & FINANCING ACTIVITIES
Acquisition of Treasury Stock in Lieu of
Receivables Owed	$	-		$	146,380		$	-

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

F-9

ROYALE ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This summary of significant accounting policies of Royale Energy, Inc. (“Royale Energy") is presented to assist in understanding Royale Energy's financial statements. The financial statements and notes are representations of Royale Energy's management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.

Description of Business

Royale Energy is an independent oil and gas producer which also has operations in the area of turnkey drilling. Royale Energy owns wells and leases in major geological basins located primarily in California, Texas, and Utah. Royale Energy offers fractional working interests and seeks to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing.

Use of Estimates

Material estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proven reserves. Estimated reserves are used in the calculation of depletion, depreciation and amortization, unevaluated property costs, estimated future net cash flows, taxes, and contingencies.

Joint Ventures

The accompanying financial statements as of December 31, 2007 and 2006 include the accounts of Royale Energy and its proportionate share of the assets, liabilities and results of operations. Royale Energy generally retains an ownership interest of approximately 50% in wells it drills with its joint venture projects. Royale Energy is the operator of the majority of properties in which it has an ownership interest. In connection with the drilling and operation of wells, the Company receives industry standard COPAS fees, which are recorded as supervisory fee income.

Revenue Recognition

Royale Energy recognizes revenues from the sales of oil and natural gas upon transfer of title, net of royalties, in the period of delivery. Settlements for oil and natural gas sales can occur up to two months after the end of the month in which the oil and natural gas were produced. We estimate and accrue for the value of these sales using information available to us at the time our financial statements are generated.

Royale Energy recognizes revenues from the sale of natural gas in which the Company has an interest with other producers using the entitlements method of accounting. Under this method we recognize revenue based on our entitled ownership percentage of sales of natural gas delivered to purchasers. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. When we receive more than our entitled share, a liability is recorded. Gas imbalances on our production at December 31, 2007, 2006 and 2005 were not significant.

F-10

Royale Energy enters into turnkey drilling agreements with investors to develop leasehold acreage it has acquired. When Royale Energy sponsors a turnkey drilling project for sale, a calculation is made to estimate the pre-drilling costs and the drilling costs. A percentage for each is calculated. The turnkey drilling project is then sold to investors who enter into a signed contract with Royale Energy. In this agreement, the investor agrees to share in the pre-drilling costs, which include lease costs, and other costs as required so that the drilling of the project can proceed. As stated in the contract, the percentage of the pre-drilling costs that the investor contributes is non-refundable, and thus on its financial statements, Royale Energy recognizes these non-refundable payments as revenue since the pre-drilling costs have commenced. The remaining investment is held and reported by Royale Energy as deferred revenue until drilling is complete. Drilling is generally completed within 10-30 days. If costs exceed revenues and Royale Energy participates as a working interest owner, Royale’s proportional share of the excess is capitalized as the cost of Royale Energy's working interest. If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, the deferred funds received would be returned to the investors. Included in cash and cash equivalents are amounts for use in the completion of turnkey drilling programs in progress.

Oil and Gas Property and Equipment (Successful Efforts)

Royale Energy accounts for its oil and gas exploration and development costs using the successful efforts method. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Significant undeveloped leases are reviewed periodically and a valuation allowance is provided for any estimated decline in value. Cost of other undeveloped leases is expensed over the estimated average life of the leases. Cost of exploratory drilling is initially capitalized. In the absence of a determination that proved reserves are found, the costs of drilling such exploratory wells is charged to expense. Royale Energy makes this determination within one year following the completion of drilling. Other exploratory costs are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Depletion, depreciation and amortization of oil and gas producing properties are computed on an aggregate basis using the units-of-production method.

Financial Accounting Standards Board (FASB), Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets ", requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. It establishes guidelines for determining recoverability based on future net cash flows from the use of the asset and for the measurement of the impairment loss. Impairment loss under SFAS No. 144 is calculated as the difference between the carrying amount of the asset and its fair value. Any impairment loss is recorded in the current period in which the recognition criteria are first applied and met. Under the successful efforts method of accounting for oil and gas operations, Royale Energy periodically assessed its proved properties for impairments by comparing the aggregate net book carrying amount of all proved properties with their aggregate future net cash flows. The statement requires that the impairment review be performed on the lowest level of asset groupings for which there are identifiable cash flows.

Royale Energy performs a periodic review for impairment of proved properties on a field-by-field basis. Unamortized capital costs are measured on a field basis and are reduced to fair value if it is determined that the sum of expected future net cash flows are less than the net book value. Royale Energy determines if impairment has occurred through either adverse changes or as a result of its periodic review for impairment. Impairment is measured on discounted cash flows utilizing a discount rate appropriate for risks associated with the related properties or based on fair market values. Impairment losses of $2,106,670, $6,191,417, and $742,642, were recorded in 2007, 2006, and 2005 respectively.

F-11

Upon the sale of oil and gas reserves in place, costs and accumulated amortization of such property are removed from the accounts and resulting gain or loss on sale is reflected in operations. Impairment of unproved properties is assessed periodically on a property-by-property basis, and any impairment in value is currently charged to expense. In addition, capitalized costs of unproved properties are assessed periodically to determine whether their value has been impaired below the capitalized costs. Loss is recognized to the extent that such impairment is indicated. In making these assessments, factors such as exploratory drilling results, future drilling plans, and lease expiration terms are considered. When an entire interest in an unproved property is sold, gain or loss is recognized, taking into consideration any recorded impairment. Upon abandonment of properties, the reserves are deemed fully depleted and any unamortized costs are recorded in the statement of income under impairment expense.

In 2007, we recorded an impairment of $2,106,670 in fields where year end reserve values no longer supported the net book values of wells in those fields. The majority of this impairment, $1,248,843 was recorded in our Bowerbank field in California, were various recently drilled wells had significantly lower proved undeveloped reserves than originally estimated. The Afton field in California was impaired for $389,946 mainly on acquired wells which ceased producing due to their natural declines and had lower reserves than originally estimated. Our Texas and Gulf Coast fields were impaired $283,371 due to wells in these areas that had been drilled in the last few years which had significantly lower production and reserves than originally estimated. Our Elkhorn Slough field was impaired for $148,734 due to lower proved undeveloped reserves than originally estimated.

In 2006, we recorded an impairment of $6,191,417 in fields where year end reserve values no longer supported the net book values of wells in those fields. The primary focus of this impairment, $4,068,843 was recorded for our wells in the Texas and Gulf Coast fields. There were several wells in this area that had been drilled in the last few years which had significantly lower production and reserves than originally estimated. The Bowerbank field in California was impaired for $1,331,093 mainly for older wells which ceased producing due to their natural declines. Our Cache Creek field was impaired for its remaining value of $399,269 due to the drilling of the North Crossroads 6-34 which proved unsuccessful. The Willows field was also impaired for $255,109 due to the drilling of the North Willows 3 which although successful had lower reserves than originally estimated.

In 2005, we recorded an impairment in our Afton field due to drilling subsequent exploratory wells which were not successful. We also recorded an impairment in the Cache Creek field due to two wells in the field, North Crossroads 1 and North Crossroads 4, watering out and ceasing production in 2005.

Reclassification

Certain items in the financial statements have been reclassified to maintain consistency and comparability for all periods presented herein. The company has determined that certain G&A charges are presented more fairly as Marketing. The reclassification is reflected in all years presented.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and on deposit, and highly liquid debt instruments with maturities of three months or less.

Inventory

Inventory consists of well supplies and spare parts and is carried at cost.

Accounts Receivable

The Company provides for uncollectible accounts receivable using the allowance method of accounting for bad debts. Under this method of accounting, a provision for uncollectible accounts is charged to earnings. The allowance account is increased or decreased based on past collection history and management’s evaluation of accounts receivable. All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance.

F-12

At December 31, 2007 and 2006, net accounts receivable was $4,090,341 and $2,906,290 respectively. At December 31, 2007 and 2006, the Company established an allowance for uncollectable accounts of $546,874 and $567,000, respectively for receivables from direct working interest investors whose expenses on non-producing wells was unlikely to be collected from revenue.

Equipment and Fixtures

Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred. Gains or losses on dispositions of property and equipment, other than oil and gas, are reflected in operations.

Earnings (Loss) Per Share

Basic and diluted earnings (loss) per share are calculated as follows:

	For the Year Ended December 31, 2007
	Income			Shares		Per-Share
	(Numerator)			(Denominator)		Amount

Basic Earnings Per Share:
Net income available to common stock	$	(2,779,207	)		7,917,543	$	(0.35	)

Cumulative effect of accounting change

Diluted Earnings Per Share:
Effect of dilutive securities and stock options

Net income available to common stock	$	(2,779,207	)		7,917,543	$	(0.35	)

	For the Year Ended December 31, 2006
	Income			Shares		Per-Share
	(Numerator)			(Denominator)		Amount

Basic Earnings Per Share:
Net income available to common stock	$	(2,649,701	)		7,932,198	$	(0.33	)

Cumulative effect of accounting change		-			-		-

Diluted Earnings Per Share:
Effect of dilutive securities and stock options		-			-		-

Net income available to common stock	$	(2,649,701	)		7,932,198	$	(0.33	)

F-13

	For the Year Ended December 31, 2005
	Income		Shares		Per-Share
	(Numerator)		(Denominator)		Amount

Basic Earnings Per Share:
Net income available to common stock	$	1,185,903		7,860,341	$	0.15

Cumulative effect of accounting change		-		-		-

Diluted Earnings Per Share:
Effect of dilutive securities and stock options		-		31,769		-

Net income available to common stock	$	1,185,903		7,892,110	$	0.15

Stock Based Compensation

Royale Energy has a stock-based employee compensation plan, which is more fully described in Note 14. Effective January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) (“SFAS No. 123R”), Share-Based Payment, which addresses the accounting for stock-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123R eliminates the ability to account for stock-based compensation transactions using the intrinsic value method under Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and instead generally requires that such transactions be accounted for using a fair-value-based method. The Company uses the Black-Scholes option-pricing model to determine the fair-value of stock-based awards under SFAS No. 123R, consistent with that used for pro forma disclosures under SFAS No. 123, Accounting for Stock-Based Compensation. The Company has elected to use the modified prospective transition method as permitted by SFAS No. 123R and accordingly prior periods have not been restated to reflect the impact of SFAS No. 123R. The modified prospective transition method requires that stock-based compensation expense be recorded for all new and unvested stock options, restricted stock, restricted stock units, and employee stock purchase plan shares that are ultimately expected to vest as the requisite service is rendered beginning on January 1, 2006. Stock-based compensation expense for awards granted prior to January 1, 2006 is based on the grant-date fair-value as determined under the pro forma provisions of SFAS No. 123. The Company recognized incremental stock-based compensation expense of $0 during 2006 as a result of the adoption of SFAS No. 123R.

Prior to the adoption of SFAS No. 123R, the Company measured compensation expense for its employee stock-based compensation plans using the intrinsic value method prescribed by APB Opinion No. 25. The Company applied the disclosure provisions of SFAS No. 123 as amended by SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure, as if the fair-value-based method had been applied in measuring compensation expense. Under APB Opinion No. 25, when the exercise price of the Company’s employee stock options was equal to the market price of the underlying stock on the date of the grant, no compensation expense was recognized.

F-14

The following table illustrates the effect on net income and earnings per share if Royale Energy had applied the fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, to stock-based compensation:

	2005
Net income (loss), as reported	$	1,185,903

Add: Stock-based employee compensation
expense included in reported net income, net
of related tax effects.		-

Deduct: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects		-

Pro forma net income	$	1,185,903

Earnings per share:
Basic — as reported	$	0.15
Basic — pro forma	$	0.15

Diluted — as reported	$	0.15
Diluted — pro forma	$	0.15

On June 1, 2005, Royale Energy awarded shares of restricted common stock to certain of its employees pursuant to an incentive compensation plan. On that date, the Company’s stock price was $5.66 per share. A total of 2,253, 4,612 and 6,048 shares of vested restricted common stock were issued in 2007, 2006 and 2005, respectively. The Company recognized $12,752, $26,105 and $34,241 compensation expense in 2007, 2006 and 2005, respectively. The stock issued pursuant to the plan was issued in reliance on the exemption from registrations requirements of the Securities Act of 1933 contained in Section 4(2) thereof. Royale Energy issued no other equity securities in 2007, 2006, or 2005.

Income Taxes

The provision for income taxes is based on pretax financial accounting income. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported net amounts.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is more likely than not to be sustained upon examination, then an enterprise would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. As discussed in Note 7, the adoption of FIN 48 effective January 1, 2007 did not materially affect our financial position or results of operations.

F-15

We have elected to classify any interest expense and penalties related to the underpayment of income taxes in “income tax expense” in our consolidated statements of income.

Fair Values of Financial Instruments

Disclosure of the estimated fair value of financial instruments is required under SFAS No. 107, "Disclosure about Fair Value of Financial Instruments." The fair value estimates are made at discrete points in time based on relevant market information and information about the financial instruments. These estimates may be subjective in nature and involve uncertainties and significant judgment and therefore cannot be determined with precision.

Royale Energy includes fair value in the notes to financial statements when the fair value of its financial instruments is different from the book value. Royale Energy assumes that the book value of financial instruments that are classified as current approximate fair value because of the short maturity of these instruments. For noncurrent financial instruments, Royale Energy uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments.

Treasury Stock

The Company records acquisition of its capital stock for treasury at cost. Differences between proceeds for reissuance of treasury stock and average cost are charged to retained earnings or credited thereto to the extent of prior charges and thereafter to capital in excess of par value.

Recently Issued Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157,) which provides expanded guidance for using fair value to measure assets and liabilities. SFAS 157 establishes a hierarchy for data used to value assets and liabilities, and requires additional disclosures about the extent to which a company measures assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. Implementation of SFAS 157 is required on January 1, 2008. We are currently evaluating the impact of adopting SFAS 157 on the financial statements.

On September 13, 2006, the Securities Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108 (SAB 108,) which establishes an approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related disclosures. SAB 108 requires the use of a balance sheet and an income statement approach to evaluate whether either of these approaches results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. The Company does not expect the adoption of SAB 108 to have an impact on the Company’s financial statements.

On September 29, 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(r)” (SFAS 158.) The Statement requires the recognition of the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability on the balance sheet and the recognition of the changes of the funded status in the year in which the changes occur through comprehensive income. Implementation of SFAS 158 is required as of the end of the fiscal year ending after December 15, 2006. The adoption of SFAS 158 did not have an impact on the Company’s financial statements because the Company does not currently have any defined benefit pension or other postretirement benefit plans.

F-16

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159) that provides an option to report selected financial assets and liabilities at fair value. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective for the second fiscal year beginning after November 15, 2007. We are currently evaluating the impact of SFAS 159 on the Company.

In December 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 160 “Noncontrolling Interest in Consolidated Financial Statements – an Amendment of ARB 51” (SFAS 160). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited.

We are currently evaluating the impact on the financial statements.

NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

Oil and gas properties, equipment and fixtures consist of the following at December 31,:

	2007			2006
Oil and Gas

Producing properties, including intangible drilling costs	$	32,479,353		$	27,876,284
Undeveloped properties		2,974,647			1,767,671
Lease and well equipment		8,069,725			7,136,142
		43,523,725			36,780,097
Accumulated depletion, depreciation and amortization		(21,098,694	)		(17,745,105	)

	$	22,425,031		$	19,034,992

Commercial and Other

Real estate, including furniture and fixtures		503,344			503,344
Vehicles		313,460			287,155
Furniture and equipment		1,200,852			1,702,127
		2,017,656			2,492,626
Accumulated depreciation		(1,052,946	)		(1,001,658	)

		964,710			1,490,968

	$	23,389,741		$	20,525,960

F-17

The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed:

	2007		2006		2005

Acquisition - Proved	$	1,690	$	720,796	$	394,069
Acquisition - Unproved	$	1,060,983	$	1,276,429	$	848,358
Development	$	3,441,517	$	7,489,178	$	7,633,536
Exploration	$	9,763,490	$	5,727,865	$	5,507,658

On April 4, 2005, the Financial Accounting Standards Board posted FSP FAS 19-1, Accounting for Suspended Well Costs, to be effective for reporting periods beginning after April 4, 2005. We have adopted FSP FAS 19-1 effective as of July 1, 2005. The guidance set forth in the FSP requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2007 or 2006. We did not charge any previously capitalized exploratory well costs to expense upon adoption of FSP FAS 19-1.

	12 Months Ended December 31,
	2007			2006
Beginning balance at January 1	$	0		$	0

Additions to capitalized exploratory well costs pending the determination of proved reserves	$	6,684,243		$	1,852,733

Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	$	(6,684,243	)	$	(1,852,733	)

Ending balance at December 31	$	0		$	0

F-18

Results of Operations from Oil and Gas Producing and Exploration Activities

The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) for the three years ended December 31, are as follows:

	2007			2006			2005

Oil and gas sales	$	6,110,092		$	7,965,633		$	11,228,537
Production related costs		(2,116,977	)		(1,968,269	)		(2,751,441	)
Geological and geophysical expense		(423,459	)		(400,306	)		(381,790	)
Lease Impairment		(2,106,670	)		(6,191,417	)		(742,642	)
Depreciation, depletion and amortization		(3,585,682	)		(5,833,904	)		(4,062,587	)

Results of operations from producing and
exploration activities	$	(2,122,696	)	$	(6,428,263	)	$	3,290,077
Income Taxes (Benefit)		(732,330	)		(2,217,751	)		1,135,077

Net Results	$	(1,390,366	)	$	(4,210,512	)	$	2,155,000

NOTE 3 – ASSET RETIREMENT OBLIGATION

In June 2001, the FASB issued FAS 143, “Accounting for Asset Retirement Obligations.” FAS 143 requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the company’s credit-adjusted risk-free interest rate. The provisions of this statement apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset.

	2007		2006
Asset retirement obligation
Beginning of the year	$	273,049	$	245,627
Liabilities incurred during the period		7,006		24,811
Settlements		0		(6,520	)
Accretion expense		10,217		9,450
Revisions in estimated cash flow		112,006		(319	)

Asset retirement obligation
End of year	$	402,278	$	273,049

NOTE 4 - TURNKEY DRILLING CONTRACTS

Royale Energy receives funds under turnkey drilling contracts, which require Royale Energy to drill oil and gas wells within a reasonable time period from the date of receipt of the funds. As of December 31, 2007 and 2006, Royale Energy had recorded deferred turnkey drilling revenue associated with undrilled wells of $3,947,097 and $5,018,261, respectively, as a current liability.

F-19

NOTE 5 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS

Royale Energy identifies reportable segments by product and country, although Royale Energy currently does not have foreign country segments. Royale Energy includes revenues from both external customers and revenues from transactions with other operating segments in its measure of segment profit or loss. Royale Energy also includes interest revenue and expense, DD&A, and other operating expenses in its measure of segment profit or loss.

The accounting policies of the reportable segments are the same as those described in the Summary of Significant Accounting Principles (see Note 1).

Royale Energy's operations are classified into two principal industry segments. Following is a summary of segmented information for 2007, 2006 and 2005

	Oil and Gas
	Producing			Turnkey
	and			Drilling
	Exploration			Services			Total
Year Ended December 31, 2007
Revenues from External Customers	$	6,110,092		$	9,408,103		$	15,518,195

Supervisory Fees		847,603						847,603

Interest Revenue		95,800			95,801			191,601

Interest Expense		76,274			76,273			152,547

Expenditures for Segment Assets		5,868,775			8,746,020			14,614,795

Depreciation, Depletion, and Amortization		3,406,398			179,284			3,585,682

Lease Impairment		2,106,670			-			2,106,670

Gain (Loss) on Sale of Assets		(67,698	)		(67,698	)		(135,396	)

Income Tax (Benefit)		(629,242	)		(629,242	)		(1,258,484	)

Total Assets	$	32,571,374					$	32,571,374

Net Income (Loss)	$	(3,843,078	)	$	1,063,871		$	(2,779,207	)

F-20

	Oil and Gas Producing And Exploration			Turnkey Drilling Services			Total

Year Ended December 31, 2006
Revenues from External Customers	$	7,965,633		$	15,711,550		$	23,677,183

Supervisory Fees	$	1,056,952		$	-		$	1,056,952

Interest Revenue	$	161,908		$	-		$	161,908

Interest Expense	$	261,570		$	261,569		$	523,139

Expenditures for Segment Assets	$	5,629,298		$	13,693,408		$	19,322,706

Depreciation, Depletion, and Amortization	$	5,542,209		$	291,695		$	5,833,904

Lease Impairment	$	6,191,417		$	-		$	6,191,417

Gain on Sale of Assets	$	3,263,368		$	-		$	3,263,368

Income Tax (Benefit)	$	(531,027	)	$	(531,027	)	$	(1,062,054	)

Total Assets	$	33,715,203		$	-		$	33,715,203

Net Income (Loss)	$	(4,645,606	)	$	1,195,905		$	(2,649,701	)

Year Ended December 31, 2005
Revenues from External Customers	$	11,228,537		$	13,066,800		$	24,295,337

Supervisory Fees	$	1,277,105		$	-		$	1,277,105

Interest Revenue	$	70,936		$	-		$	70,936

Interest Expense	$	222,136		$	222,135		$	444,271

Expenditures for Segment Assets	$	6,245,208		$	12,335,497		$	18,580,705

Depreciation, Depletion, and Amortization	$	3,859,458		$	203,129		$	4,062,587

Lease Impairment	$	371,321		$	371,321		$	742,642

Income Tax (Benefit)	$	313,635		$	313,635		$	627,270

Total Assets	$	43,042,581		$	-		$	43,042,581

Net Income (Loss)	$	1,564,821		$	(378,918	)	$	1,185,903

F-21

NOTE 6 - LONG-TERM DEBT

	2007		2006
Revolving line of credit secured by oil and gas properties, with a maximum available of $5,375,974 at December 31, 2007 issued by Guaranty Bank, FSB for the purposes of refinancing Royale’s existing debt and to fund development, exploration and acquisition activities as well as other general corporate purposes. The agreement was entered into on January 21, 2003. Interest is at Guaranty Bank’s base rate plus .75%, resulting in a rate of 7.75% and 8.75% at December 31, 2007 and 2006, respectively, payable monthly with borrowing base reductions of $200,000 commencing on January 1, 2008. As part of this agreement, Guaranty Bank has issued letters of credit in the amount of $774,025 on behalf of the Company to various agencies. All unpaid principal and interest is payable at maturity on October 1, 2010.	$	5,175,974	$	3,810,000

Term Note (Secured by Deed of Trust), dated March 17, 2004, in the original principal amount of $1,000,000, executed by Royale Energy, Inc., payable to the order of Guaranty Bank, FSB. Monthly payments of principal and interest are $9,000 per month. The unpaid principal and interest due was paid on March 19, 2007.		0	$	233,045

Total Long Term Debt	$	5,175,974	$	4,043,045

Less Current Maturity		0	$	(233,045	)

Long Term Debt Less Current Portion	$	5,175,974	$	3,810,000

Significant covenants under the terms of the line of credit agreement include that the Company will have a tangible net worth not less than $8,188,000 as of September 30, 2002, plus 50% of positive quarterly net income thereafter, a debt coverage ratio not less than 1.25:1, a bank defined current ratio not less than 1:1, general and administrative expenses (excluding litigation and accounting expenses) at the close of any fiscal quarter not to exceed 27.5% of net revenues. The Company was in compliance with, or had obtained a waiver from, the terms of this agreement at December 31, 2007 and 2006.

Maturities of long-term debt for years subsequent to December 31, 2007 are as follows:

Year Ended
December 31,

2008	$	0
2009		0
2010		5,175,974
	$	5,175,974

F-22

NOTE 7 - INCOME TAXES

Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

Significant components of the Company’s deferred assets and liabilities at December 31, 2007, 2006 and 2005, respectively, are as follows:

	2007			2006			2005
Deferred Tax Assets (Liabilities):
Statutory Depletion Carry Forward	$	689,985		$	129,433		$	816,270
Net Operating Loss		421,982
Other		8,024
Capital Loss / AMT Credit Carry Forward		18,915			22,465			25,311
Charitable Contributions Carry Forward		383			-			6,660
Allowance for Doubtful Accounts		209,179			195,615			124,097
Oil and Gas Properties and Fixed Assets		(1,577,216	)		(1,825,820	)		(4,669,918	)
	$	(228,748	)	$	(1,478,307	)	$	(3,697,580	)
Valuation Allowance		(134,847	)		-			-
Net Deferred Tax Liability	$	(363,595	)	$	(1,478,307	)	$	3,697,580	)

Deferred Tax Assets:
Current	$	217,586		$	195,615		$	194,468
Non-current					-			-
Deferred Tax Liabilities:
Current					-			-
Non-current		(581,181	)		(1,673,922	)		(3,892,048	)
Net Deferred Tax Liability	$	(363,595	)	$	(1,478,307	)	$	(3,697,580	)

The Company had statutory percentage depletion carry forwards of approximately $1,800,000 and $375,168 at December 31, 2007 and 2006, respectively. The depletion has no expiration date. The Company also has a net operating loss carry forward of approximately $1,100,000 and $0 at December 31, 2007 and 2006, respectively.

F-23

A reconciliation of Royale Energy's provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2007, 2006 and 2005, respectively, to pretax income is as follows:

	2007			2006			2005

Tax (benefit) computed at statutory rate	$	(1,372,815	)	$	(1,279,100	)	$	625,440

Increase (decrease) in taxes resulting from:

State tax / percentage depletion / other		(23,503	)		211,712			-
Other non deductible expenses		2,987			5,334			1,830
Change in valuation allowance		134,847			-			-
Provision (benefit)	$	(1,258,484	)	$	(1,062,054	)	$	627,270

Effective Tax Rate		31.2	%		28.6	%		34.6	%

The components of the Company’s tax provision are as follows:

	2007			2006			2005

Current tax provision (benefit) – federal	$	(171,795	)	$	915,010		$	5,570
Current tax provision (benefit) – state		28,023			242,209			629
Deferred tax provision (benefit) – federal		(1,120,479	)		(1,754,774	)		558,064
Deferred tax provision (benefit) – state		5,767			(464,499	)		63,007

Total provision (benefit)	$	(1,258,484	)	$	(1,062,054	)	$	627,270

We adopted the provisions of FASB Interpretation (“FIN”) 48, Accounting for Uncertainty in Income Taxes — an interpretation of Statement of Financial Accounting Standards (“SFAS”) 109 on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. As a result of our implementation of FIN 48 at the time of adoption and December 31, 2007, the Company did not recognize a liability for uncertain tax positions. As a result, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our consolidated balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2000 through 2007 remain open to examination by the taxing jurisdictions in which we file income tax returns.

NOTE 8 - REDEEMABLE PREFERRED STOCK

In 1993, Royale Energy's Board of Directors authorized the issuance of 259,250 shares of Series A Convertible Preferred Stock. The Stock is convertible any time at the basic conversion rate of one share of common stock for two shares of Series A Convertible Preferred Stock, subject to adjustment.

There were no common stock conversions in 2005. In June 2006, we issued 3,060 shares of common stock to one stockholder on conversion of the remaining outstanding shares of our Series A convertible preferred stock to common, pursuant to the conversion terms of the Series A preferred.

F-24

NOTE 9 - SERIES AA PREFERRED STOCK

In April 1992, Royale Energy's Board of Directors authorized the sale of Series AA Convertible Preferred Stock. Holders of Series AA Convertible Preferred Stock have dividend, conversion and preference rights identical to Series A Convertible Preferred Stockholders. The Series AA Convertible Preferred Stock does not have the right of redemption at the stockholders' option. As of December 31, 2003 and 2002, there were 43,240 and 48,581 shares issued and outstanding. The Board authorized a 15% stock dividend to stockholders of record on May 31, 2002 and increased the number of Series AA Preferred shares by 6,466. In addition, on May 1, 2003, the Board authorized a 15% stock dividend to stockholders of record on that date payable in equal monthly installments beginning with the quarter ending June 30, 2003. This dividend increased the number of Series AA Preferred shares by 3,701 for the period ending December 31, 2003 and has been retroactively restated to reflect the 3^rd quarterly stock dividend paid in January 2004. On March 31, 2004, the fourth and final of these installments was made resulting in 1,619 shares being issued. On March 23, 2004, the Board of Directors declared a 28% stock split, which was distributed to stockholders on June 30, 2004. As a result, the Series AA Preferred shares increased by 12,557. As of December 31, 2007 and 2006, there were 57,416 shares issued and outstanding.

NOTE 10 - COMMON STOCK

On March 23, 2004, the Board of Directors declared a 28% stock split issued in the form of a stock dividend, which was distributed to stockholders on June 30, 2004. As a result, the number of common shares increased by 1,712,093. There were no stock dividends during the years ended December 31, 2007 or 2006.

NOTE 11 – SUBSEQUENT EVENTS

At the March 12, 2008 Board of Directors meeting, directors and executive officers of Royale Energy were each granted 45,000 options to purchase common stock at an exercise or base price of $3.50 per share. These options are to be vested in three parts, the first 15,000 will vest March 31, 2008 and 15,000 in each of the next two years March 31, 2009 and March 31, 2010. They were granted for a period of four years.

F-25

NOTE 12 - OPERATING LEASES

Royale Energy occupies office space through the use of two leases, one for their office in San Diego, CA and one for an office in Woodland, CA. The San Diego lease is under a 120 month noncancellable lease contract, which expires in July 2015. The San Diego lease calls for monthly payments ranging from $27,010 to $35,271, and the Woodland lease calls for monthly payments of $275. Future minimum lease obligations as of December 31, 2007 are as follows:

Year Ended
December 31,

2008	$	348,689
2009		358,857
2010		369,555
2011		380,465
2012		391,692
Thereafter		1,066,614

Total	$	2,915,872

Rental expense for the years ended December 31, 2007, 2006, and 2005 are $403,497, $370,658, and $340,006, respectively.

NOTE 13 - RELATED PARTY TRANSACTIONS

Significant Ownership Interests

Donald H. Hosmer, Royale Energy’s president, owns 11.27% of Royale Energy common stock. Donald H. Hosmer is the brother of Stephen M. Hosmer, and son of Harry E. Hosmer.

Stephen M. Hosmer, Royale Energy’s executive vice president and chief financial officer, owns 14.74% of Royale Energy common stock. Stephen M. Hosmer is the brother of Donald H. Hosmer and son of Harry E. Hosmer.

Harry E. Hosmer, Royale Energy's former president and former chief executive officer, owns 9.65% of Royale Energy common stock. Donald H. and Stephen M. Hosmer are sons of Harry E. Hosmer. Donald H. Hosmer and Stephen M. Hosmer are also officers and directors of Royale Energy.

The Board of Directors adopted a policy in 1989 that permits directors and officers of the Company to purchase from the Company, at the Company’s actual costs, up to one percent of a fractional interest in any well to be drilled by the Company. Current and former officers and directors were billed $21,759, $49,787 and $130,473 for their interests for the years ended December 31, 2007, 2006 and 2005, respectively.

For the year ended December 31, 2005, Royale Energy repurchased 19,615 stock options held by Stephen Hosmer amounting to $188,912. For the year ended December 31, 2004, the company repurchased 14,063 stock options held by Harry Hosmer, and 11,078 held by Don Hosmer, amounting to $160,178 and $126,178 respectively. For the year ended December 31, 2003 the company repurchased 10,290 options from Don Hosmer and 42,000 from Harry Hosmer amounting to $59,270 and $275,854 respectively.

F-26

Donald H. Hosmer delivered 26,000 shares of common stock of Royale Energy, Inc., owned by him, to the company on September 26, 2006, in exchange for interests in oil and gas drilling projects sponsored by the company. The value of the common stock received by the company in consideration for the exchange was $146,380, based on the closing market price of the company's common stock on the NASDAQ Stock Market on June 12, 2006, the date the agreement to invest was made. Mr. Hosmer continues to hold the remainder of his common shares, equal to 12.51% of the company's common stock, as an investment.

NOTE 14 - STOCK COMPENSATION PLAN

On December 18, 1992, the Board of Directors granted the directors and executive officers of Royale Energy 30,000 options to purchase common stock at an exercise or base price of $3.00 per share. All options are exercisable on or after the second anniversary of the date of the grant. Also on this date, the Board of Directors voted to adopt a policy of awarding stock options to key employees and contractors based on performance. In 2005, 109,686 options were exercised at $1.13 per share and 27,457 options expired.

At the March 10, 1995 Board of Directors meeting, directors and executive officers of Royale Energy were granted 154,000 options to purchase common stock at an exercise or base price of $1.90 per share. These options were granted for a period of ten years, and may be exercised after the second anniversary of the grant. Royale Energy applies APB Opinion 25 and related interpretations in accounting for its plans. Royale Energy did not grant stock options during 2007, 2006, or 2005.

A summary of the status of Royale Energy's stock option plan as of December 31, 2007, 2006 and 2005, and changes during the years ending on those dates is presented below:

	2007				2006				2005
			Weighted-				Weighted-					Weighted-
			Average				Average					Average
			Exercise				Exercise					Exercise
	Shares		Price		Shares		Price		Shares			Price

Fixed Options
Outstanding at Beginning of Year		0		-		0		-		137,143		$	1.13
Stock Dividends and Splits		-				-				-
Reinstated		-				-				-
Exercised		-				-				(109,686	)
Expired or Ineligible		-				-				(27,457	)

Outstanding at End of Year		0		-		0		-		0		$	0.97

Options Exercisable at Year End		-		-		-		-		-		$	0.97

Weighted-average Fair Value of Options
Granted During the Year		-				-				-

NOTE 15 - SIMPLE IRA PLAN

In April 1998, the Company established a Simple IRA pension plan covering all employees. The Company will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2007, 2006, and 2005 were $53,761, $48,986 and $48,445, respectively.

F-27

NOTE 16 - ENVIRONMENTAL MATTERS

Royale Energy has established procedures for the continuing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of its operational and accounting policies related to environmental issues. The nature of Royale Energy's business requires routine day-to-day compliance with environmental laws and regulations. Royale Energy incurred no material environmental investigation, compliance and remediation costs in 2007, 2006, or 2005.

Royale Energy is unable to predict whether its future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect the results of operations of Royale Energy.

NOTE 17 - CONCENTRATIONS OF CREDIT RISK

The Company bids its gas sales on a month to month basis and generally sells to a single customer without commitment to future gas sales to any particular customer. The Company normally sells approximately 93% of its monthly natural gas production to one customer on a month to month basis. Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse affect on our overall sales operations.

The Company maintains cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $100,000. At December 31, 2007 and 2006, cash in banks exceeded the FDIC limits by approximately $4.6 and $8.1 million, respectively. The Company has not experienced any losses on deposits.

F-28

NOTE 18 : Quarterly Financial Information (Unaudited):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total Year
2007
Revenues	$	2,518,837		$	4,069,220		$	4,777,239		$	5,192,103		$	16,557,399
Operating income (loss)		(1,344,016	)		(119,840	)		(138,160	)		(2,283,128	)		(3,885,144	)
Net income (loss)	$	(912,010	)	$	(105,350	)	$	(121,125	)	$	(1,640,722	)	$	(2,779,207	)
Earnings (loss) per share
Basic and Diluted	$	(0.12	)	$	(0.01	)	$	(0.02	)	$	(0.21	)	$	(0.35	)

2006
Revenues	$	7,383,723		$	4,607,688		$	4,630,815		$	8,273,817		$	24,896,043
Operating income (loss)		1,173,242			124,612			(922,973	)		(3,563,497	)		(3,188,616	)
Net income (loss)	$	687,020		$	9,024		$	(767,137	)	$	(2,578,608	)	$	(2,649,701	)
Earnings (loss) per share
Basic and Diluted	$	0.09		$	0.00		$	(0.10	)	$	(0.32	)	$	(0.33	)

Annual Earnings (loss) per share may not equal the sum of the four quarterly amounts due to rounding.

NOTE 19: COMMITMENTS AND CONTINGENCIES

The Company may become involved from time to time in litigation on various matters, which are routine to the conduct of its business. The Company believes that none of these actions, individually or in the aggregate, will have a material adverse effect on its financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on its business.

Pioneer Exploration Ltd v. Royale Energy, No. 56969, Superior Court of Tehama County, California. On February 15, 2006, Pioneer Exploration, Ltd., filed suit against Royale Energy for declaratory relief and money damages related to certain properties covered by a joint operating agreement between the plaintiff and Royale Energy. The dispute stems from the assignment of interest from Blue Star Resources to Pioneer Exploration Ltd, and the resulting rights of Pioneer under the operating agreement. Pioneer alleges that Royale did not have the right to directionally drill a well in which Pioneer was a participant, and that Pioneer should have been allowed to participate in the drilling of one other well. The Company denies the allegation and will vigorously defend itself against these claims to the fullest extent possible.

F-29

ROYALE ENERGY, INC.

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by Royale Energy located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.

Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent engineering consultants for the years ended December 31, 2007, 2006, and 2005. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves.

These estimates are furnished and calculated in accordance with requirements of the Financial Accounting Standards Board and the Securities and Exchange Commission (SEC). Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent management's assessment of future profitability or future cash flows to Royale Energy. Management's investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.

It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value of proved reserves.

Changes in Estimated Reserve Quantities

The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2007, 2006 and 2005 and changes in such quantities during each of the years then ended, were as follows:

	2007						2006						2005
	Oil (BBL)			Gas (MCF)			Oil (BBL)			Gas (MCF)			Oil (BBL)			Gas (MCF)
Proved developed and undeveloped reserves:
Beginning of period		37,000			8,160,000			91,000			10,564,000			317,000			12,624,000
Revisions of previous estimates		954			(4,048,438	)		(34,444	)		(1,022,969	)		(104,235	)		(1,013,667	)
Production		(14,088	)		(791,195	)		(21,325	)		(1,074,573	)		(16,557	)		(1,384,860	)
Extensions, discoveries and improved recovery					784,391			2,331			1,866,918			9,000			1,952,299
Purchase of minerals in place								0			0			-			-
Sales of minerals in place					(332,791	)		(563	)		(2,173,376	)		(114,208	)		(1,613,772	)

Proved reserves end of period		23,866			3,771,967			37,000			8,160,000			91,000			10,564,000

F-30

	2007				2006				2005
	Oil (BBL)		Gas (MCF)		Oil (BBL)		Gas (MCF)		Oil (BBL)		Gas (MCF)

Proved developed reserves:

Beginning of period		37,000		4,129,000		65,000		6,990,000		146,000		8,135,000

End of period		23,866		3,413,578		37,000		4,129,000		65,000		6,990,000

These estimates were determined using gas prices at December 31, 2007 ranging from $3.83 per MCF to $7.77 per MCF as applied on a field-by-field basis.

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

The standardized measure of discounted future net cash flows is presented below for the three years ended December 31, 2007.

The future net cash inflows are developed as follows:

Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.

The estimated future production of proved reserves is priced on the basis of year-end prices.

The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development cost by year are as follows:


2008	$	821,700
2009		237,100
2010		17,300
Thereafter		9,200

Total	$	1,085,300

The resulting future net revenue streams are reduced to present value amounts by applying a ten percent discount.

Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.

F-31

Changes in standardized measure of discounted future net cash flow from proved reserve quantities

This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.

	2007			2006			2005

Future cash inflows	$	28,421,000		$	55,931,000		$	95,339,000
Future production costs		(7,474,000	)		(11,628,000	)		(18,086,000	)
Future development costs		(1,085,000	)		(10,779,000	)		( 9,416,000	)
Future income tax expense		(5,958,270	)		(10,057,200	)		(20,351,400	)

Future net cash flows		13,903,730			23,466,800			47,485,600

10% annual discount for estimated timing of cash flows		(3,258,848	)		( 6,820,249	)		(12,682,159	)

Standardized measure –of discounted future net cash flows	$	10,644,882		$	16,646,551		$	34,803,441

Sales of oil and gas produced, net of production costs	$	(3,858,679	)	$	(4,745,695	)	$	(7,022,572	)

Revisions of previous quantity estimates		(8,124,443	)		( 15,871,556	)		( 2,814,698	)
Net changes in prices and production costs		(1,649,513	)		( 4,015,314	)		1,269,384
Sales of minerals in place		(220,631	)		( 7,906,688	)		( 3,947,974	)
Purchases of minerals in place		-			-			-

Extensions, discoveries and improved recovery		3,741,753			4,216,939			8,593,335

Accretion of discount		1,537,700			2,383,900			4,668,700

Net change in income tax		2,572,144			7,781,524			( 223,852	)

Net increase (decrease)	$	(6,001,669	)		(18,156,890	)	$	522,323

F-32

Future Development Costs

In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the years 2008 through 2010.

Future development cost of:	2008		2009		2010
Proved developed reserves	$	-	$	-	$	-
Proved non-producing reserves		172,400		12,100		17,300
Proved undeveloped reserves		649,300		225,000		-

Total	$	821,700	$	237,100	$	17,300

Common assumptions include such matters as the real extant and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate. If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated.

Additional data relating to Royale Energy's oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy's Financial Statements, beginning on page F-1. The oil and natural gas reserve information disclosed in the supplement to the financial statements are based upon the reserve reports for the three years ended December 31, 2007, 2006, and 2005, prepared by Royale Energy's independent reserve engineering consultants.

Historic Development Costs for Proved Reserves

In each year we expend funds to drill and develop some of our proved undeveloped reserves. The following table summarizes our historic costs incurred in each of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year:

2007	$	2,093,801
2006	$	2,492,985
2005	$	2,428,069

F-33

ROYALE ENERGY, INC.

BALANCE SHEETS

	September 30, 2008		December 31, 2007
	(Unaudited)		(Audited)
ASSETS

Current Assets
Cash and cash equivalents	$	6,663,717	$	3,848,968
Accounts receivable		4,542,624		4,090,341
Prepaid expenses		1,231,933		673,453
Deferred tax asset		217,586		217,586
Investments (available for sale)		177,533		0
Inventory		182,219		344,339

Total Current Assets		13,015,612		9,174,687

Other assets		6,946		6,946

Oil and Gas Properties at cost, (successful efforts
basis), Equipment and Fixtures		21,756,031		23,389,741

TOTAL ASSETS:	$	34,778,589	$	32,571,374

See notes to unaudited financial statements

F-34

ROYALE ENERGY, INC.

BALANCE SHEETS

	September 30, 2008			December 31, 2007
	(Unaudited)			(Audited)
LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities
Accounts payable and accrued expenses	$	5,001,620		$	10,080,034
Deferred revenue from turnkey drilling		8,152,540			3,947,097
Total Current Liabilities		13,154,160			14,027,131

Noncurrent Liabilities
Asset retirement obligation		429,961			402,278
Deferred tax liability		1,172,030			581,181
Long-term debt, net of current portion		2,575,974			5,175,974
Total Noncurrent Liabilities		4,177,965			6,159,433

Total Liabilities		17,332,125			20,186,564

Stockholders' Equity
Common stock, no par value, authorized 10,000,000 shares, 8,538,717 and 7,951,746 shares issued; 8,505,630 and 7,918,659 shares outstanding, respectively		23,355,926			19,511,963
Convertible preferred stock, Series AA, no par value, 147,500 shares authorized; 52,784 and 57,416 shares issued; 52,784 and 54,416 shares outstanding, respectively		154,014			167,979
Accumulated Deficit		(5,934,434	)		(7,140,695	)
Accumulated Other Comprehensive Loss		(30,666	)		0
Total common stock, preferred stock and accumulated deficit		17,544,840			12,539,247
Less cost of treasury stock, 33,087 and 33,087 shares		(181,012	)		(181,012	)
Additional paid in capital		82,636			26,575


Total Stockholders' Equity		17,446,464			12,384,810

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY:	$	34,778,589		$	32,571,374

See notes to unaudited financial statements

F-35

ROYALE ENERGY, INC.

STATEMENTS OF OPERATIONS

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)

Revenues:
Sale of Oil and Gas	$	1,745,103		$	1,298,165		$	5,835,278		$	4,552,179
Turnkey drilling		3,016,909			3,207,261			6,269,545			6,021,892
Supervisory Fees and Other		196,310			271,813			554,323			791,225
Total Revenues		4,958,322			4,777,239			12,659,146			11,365,296

Costs and Expenses:
General and Administrative		1,016,682			1,069,442			3,041,235			3,345,386
Turnkey Drilling and Development		1,847,797			1,519,535			2,926,379			2,956,819
Geological and Geophysical Expense		0			0			0			0
Lease Operating		590,210			587,772			1,861,884			1,970,147
Lease Impairment		770,862			32,930			820,966			34,894
Legal and Accounting		61,413			345,076			1,067,197			629,480
Marketing		377,605			323,434			916,625			1,080,631
Depreciation, Depletion and Amortization		795,897			1,037,210			2,601,622			2,905,024
Total Costs and Expenses		5,460,466			4,915,399			13,235,908			12,922,381

Gain (Loss) on Sale of assets		2,630,400			0			2,602,577			(44,931	)

Income (Loss) From Operations		2,128,256			(138,160	)		2,025,815			(1,602,016	)
Other Expense:
Interest expense		45,299			41,729			195,408			116,435

Income Before Income Tax Expense		2,082,957			(179,889	)		1,830,407			(1,718,451	)
Income tax provision		709,466			(58,764	)		624,146			(579,966	)

Net Income Before Cumulative Effect of Accounting Chg		1,373,491			(121,125	)		1,206,261			(1,138,485	)
Cumulative Effect of Accounting Change		0			0			0			0

Net Income (Loss)	$	1,373,491		$	(121,125	)	$	1,206,261		$	(1,138,485	)

Diluted Earnings Per Share	$	0.16		$	(0.02	)	$	0.15		$	(0.14	)

Basic Earnings Per Share	$	0.16		$	(0.02	)	$	0.15		$	(0.14	)

Other Comprehensive Income
Unrealized Loss on Equity Securities		(53,267	)		0			(53,267	)		0
Less: Reclassification Adjustment for Losses
Included in Net Income		6,804			0			6,804			0
Other Comprehensive Loss, before tax		(46,463	)		0			(46,463	)		0
Income Tax Benefit Related to Items of
Other Comprehensive Loss		(15,797	)		0			(15,797	)		0

Other Comprehensive Loss, net of tax		(30,666	)		0			(30,666	)		0

Comprehensive Income (Loss)		1,342,825			(121,125	)		1,175,595			(1,138,485	)

See notes to unaudited financial statements

F-36

ROYALE ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

	2008			2007
	(Unaudited)			(Unaudited)

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	1,206,261		$	(1,138,485	)
Adjustments to Reconcile Net Income to Net
Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		2,601,622			2,905,024
Lease Impairment		820,966			34,894
(Gain) Loss on Sale of Assets		(2,602,577	)		44,931
Realized Loss on Equity Securities		6,804			0
Bad Debt Expense		0			0
Compensation Expense - Director's Stock Options		56,061			12,752
(Increase) Decrease in:
Accounts Receivable		(452,283	)		(64,548	)
Prepaid Expenses and Other Assets		(396,360	)		1,498,098
Increase (Decrease) in:
Accounts Payable and Accrued expenses		(5,050,731	)		994,466
Deferred Revenues - DWI		4,205,443			668,029
Deferred Income Taxes		606,646			(651,123	)
Net Cash Provided by Operating Activities		1,001,852			4,304,038

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Oil and Gas Properties
and Other Capital Expenditures		(4,885,213	)		(5,192,002	)
Proceeds from Sale of Assets		5,698,911			117,870
Purchase of Equity Securities		(250,440	)
Sale of Equity Securities		19,641			0
Net Cash Used by Investing Activities		582,899			(5,074,132	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt		0			0
Principal Payments on Long-Term Debt		(2,600,000	)		(2,318,045	)
Dividends Paid		0			(397,049	)
Proceeds from Issuance of Common Stock		3,724,999			0
Proceeds from Stock Options Exercise		105,000			0
Net Cash Provided (Used) by Financing Activities		1,229,999			(2,715,094	)

Net Increase (Decrease) in Cash and Cash Equivalents		2,814,749			(3,485,188	)

Cash at Beginning of Year		3,848,968			7,377,604

Cash at End of Period	$	6,663,717		$	3,892,416

SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:
Cash Paid for Interest	$	200,535		$	141,564

Cash Paid for Taxes	$	17,500		$	571,157

SUPPLEMENTAL DISCLOSURES OF NON CASH INVESTING & FINANCING ACTIVITIES:
Conversion of Series AA Stock to Common Stock	$	13,965		$	0

See notes to unaudited financial statements

F-37

ROYALE ENERGY, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

NOTE 1 – In the opinion of management, the accompanying unaudited financial statements include all adjustments, consisting only of normally recurring adjustments, necessary to present fairly the Company’s financial position and the results of its operations and cash flows for the periods presented. The results of operations for the nine month period are not, in management’s opinion, indicative of the results to be expected for a full year of operations. It is suggested that these financial statements be read in conjunction with the financial statements and the notes thereto included in the Company’s latest annual report.

NOTE 2 – EARNINGS PER SHARE

Basic and diluted earnings (loss) per share are calculated as follows:

	For the Nine Months ended September 30, 2008
	Income (Numerator)		Shares (Denominator)		Per-Share Amount
Basic Earnings (Loss) Per Share:
Net income available to common stock	$	1,206,261		8,158,570	$	0.15

Diluted Earnings (Loss) Per Share:
Effect of dilutive securities and stock options		0		49,309		0.00

Net income available to common stock	$	1,206,261		8,207,879	$	0.15

	For the Nine Months ended September 30, 2007
	Income (Numerator)			Shares (Denominator)		Per-Share Amount
Basic Earnings (Loss) Per Share:
Net income available to common stock	$	(1,138,485	)		7,917,543	$	(0.14	)

Diluted Earnings (Loss) Per Share:
Effect of dilutive securities and stock options		0			0		0.00

Net income available to common stock	$	(1,138,485	)		7,917,543	$	(0.14	)

F-38

ROYALE ENERGY, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

NOTE 3 – OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

Oil and gas properties, equipment and fixtures consist of the following:

	September 30, 2008			December 31, 2007
Oil and Gas
Producing properties, including drilling costs	$	32,860,371		$	32,479,353
Undeveloped properties		3,172,796			2,974,647
Lease and well equipment		8,064,201			8,069,725
		44,097,368			43,523,725
Accumulated depletion, depreciation & amortization		(23,256,028	)		(21,098,694	)
		20,841,340			22,425,031
Commercial and Other
Real estate, including furniture and fixtures	$	503,344		$	503,344
Vehicles		313,460			313,460
Furniture and equipment		1,231,438			1,200,852
		2,048,242			2,017,656
Accumulated depreciation		(1,133,551	)		(1,052,946	)
		914,691			964,710

	$	21,756,031		$	23,389,741

On April 4, 2005, the Financial Accounting Standards Board posted FSP FAS 19-1, Accounting for Suspended Well Costs, to be effective for reporting periods beginning after April 4, 2005. We have adopted FSP FAS 19-1 effective as of July 1, 2005. The guidance set forth in the FSP requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during the first nine months of 2008 or 2007.

	Nine Months ended September 30,
	2008			2007
Beginning balance at January 1	$	0		$	0
Additions to capitalized exploratory well costs pending the determination of proved reserves		497,889			2,100,508
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		(497,889	)		(2,100,508	)
Ending balance at September 30	$	0		$	0

F-39

ROYALE ENERGY, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

NOTE 4 – STOCK BASED COMPENSATION

Royale Energy has a stock-based compensation plan. Effective January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) (“SFAS No. 123R”), Share-Based Payment, which addresses the accounting for stock-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123R eliminates the ability to account for stock-based compensation transactions using the intrinsic value method under Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and instead generally requires that such transactions be accounted for using a fair-value-based method. The Company uses the Black-Scholes option-pricing model to determine the fair-value of stock-based awards under SFAS No. 123R, consistent with that used for pro forma disclosures under SFAS No. 123, Accounting for Stock-Based Compensation. The Company has elected to use the modified prospective transition method as permitted by SFAS No. 123R and accordingly prior periods have not been restated to reflect the impact of SFAS No. 123R. The modified prospective transition method requires that stock-based compensation expense be recorded for all new and unvested stock options, restricted stock, restricted stock units, and employee stock purchase plan shares that are ultimately expected to vest as the requisite service is rendered beginning on January 1, 2006. Stock-based compensation expense for awards granted prior to January 1, 2006, is based on the grant-date fair-value as determined under the pro forma provisions of SFAS No. 123.

At the March 12, 2008, Board of Directors meeting, directors and executive officers of Royale Energy were each granted 45,000 options to purchase common stock at an exercise or base price of $3.50 per share. These options are to be vested in three parts; the first 15,000 have vested March 31, 2008, and 15,000 that will vest in each of the next two years March 31, 2009 and 2010. They were granted for a period of four years. The Company recognized share-based compensation expense of $56,061 and $0 for the nine months ended September 30, 2008 and 2007, respectively.

NOTE 5 – RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In September 2006, the FASB issued SFAS 157 “Fair Value Measurements”, which provides expanded guidance for using fair value to measure assets and liabilities. SFAS 157 establishes a hierarchy for data used to value assets and liabilities, and requires additional disclosures about the extent to which a company measures assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. Implementation of SFAS 157 is required on January 1, 2008. We are currently evaluating the impact of adopting SFAS 157 on the financial statements.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159), that provides an option to report selected financial assets and liabilities at fair value. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective for the first fiscal year beginning after November 15, 2007. We are currently evaluating the impact of SFAS 159 on the Company.

On December 12, 2007, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force on Issue No. 07-01 “Accounting for Collaborative Arrangements”. This Issue will be effective for the fiscal year beginning January 1, 2009. This pronouncement is not expected to have a material impact on our financial statements.

F-40

In December 2007, the FASB issued SFAS 141(R), “Business Combinations — a Replacement of FASB Statement No. 141”, which significantly changes the principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This statement is effective prospectively, except for certain retrospective adjustments to deferred tax balances, for fiscal years beginning after December 15, 2008. We are currently evaluating the impact on the financial statements.

In March 2008, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 161 “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS 161), that requires new and expanded disclosures regarding hedging activities. These disclosures include, but are not limited to, a proscribed tabular presentation of derivative data, financial statement presentation of fair values on a gross basis, including those that currently qualify for netting under FASB Interpretation No. 39, and specific footnote narrative regarding how and why derivatives are used. The disclosures are required in all interim and annual reports. SFAS 161 is effective for fiscal and interim periods beginning after November 15, 2008. This pronouncement is not expected to have a material impact on our financial statements.

NOTE 6 – FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS

F-41

Royale Energy's operations are classified into two principal industry segments. Following is a summary of segmented information for the nine months ended September 30, 2008 and 2007:

	Oil and Gas
	Producing		Turnkey
	and		Drilling
	Exploration		Services			Total
Nine Months Ended September 30, 2008:
Revenues from External Customers	$	5,835,278	$	6,269,545		$	12,104,823

Supervisory Fees	$	473,489	$	0		$	473,489

Interest Revenue	$	0	$	80,834		$	80,834

Interest Expense	$	97,704	$	97,704		$	195,408

Expenditures for Segment Assets	$	4,285,859	$	5,527,461		$	9,813,320

DD&A	$	2,471,541	$	130,081		$	2,601,622

Lease Impairment	$	410,483	$	410,483		$	820,966

Gain (Loss) on Sale of Assets	$	2,602,577	$	0		$	2,602,577

Income Tax Expense (Benefit)	$	312,073	$	312,073		$	624,146

Total Assets	$	34,778,589	$	0		$	34,778,589

Net Income	$	1,333,684	$	(127,423	)	$	1,206,261

F-42

	Oil and Gas
	Producing			Turnkey
	and			Drilling
	Exploration			Services			Total
Nine Months Ended September 30, 2007:
Revenues from External Customers	$	4,552,179		$	6,021,892		$	10,574,071

Supervisory Fees	$	631,909					$	631,909

Interest Revenue	$	159,316					$	159,316

Interest Expense	$	58,218		$	58,217		$	116,435

Expenditures for Segment Assets	$	4,315,318		$	5,667,145		$	9,982,463

DD&A	$	2,759,773		$	145,251		$	2,905,024

Lease Impairment	$	17,447		$	17,447		$	34,894

Gain (Loss) on Sale of Assets	$	(22,466	)	$	(22,465	)	$	(44,931	)

Income Tax Expense (Benefit)	$	(289,983	)	$	(289,983	)	$	(579,966	)

Total Assets	$	30,885,749					$	30,885,749

Net Income	$	(1,539,835	)	$	401,350		$	(1,138,485	)

F-43

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

JUNE 30, 2008 AND 2007

	June 30,		June 30,
	2008		2007
ASSETS
Current assets:
Cash and cash equivalents	$	1,595,150	$	4,057,279
Marketable securities		930,818		1,120,485
Accounts and trade receivables		2,287,519		2,136,609
Other current assets		39,474		33,609

Total current assets		4,852,961		7,347,982

Property and equipment
Oil and gas property		23,677,355		19,802,843
Support equipment		183,374		184,514

		23,860,729		19,987,357

Accumulated depletion and impairment - full cost pool		(10,479,466		(8,083,383	)
Accumulated depreciation - support equipment		(70,570		(49,304	)

Net property and equipment		13,310,693		11,854,670

Other assets:
Deposits		263,650		263,650
Deferred income taxes		1,573,500		1,673,000

Total other assets		1,837,150		1,936,650

Total assets	$	20,000,804	$	21,139,302

				(Statement Continues)

See accompanying notes to these consolidated financial statements.

F-44

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)

JUNE 30, 2008 AND 2007

	June 30,		June 30,
	2008		2007
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	2,260,611	$	2,961,100
Other current liabilities and accrued expenses		620,875		1,690,709
Notes payable - current portion		475,000		275,000
Asset retirement obligation, current portion		56,400		39,400
Deferred income taxes, current		122,000		342,000
Total current liabilities		3,534,886		5,308,209
Long-term liabilities
Notes payable, net of current portion		116,667		591,667
Asset retirement obligation, net of current portion		675,955		447,253
Deferred income taxes		3,971,500		3,786,000
Total long-term liabilities		4,764,122		4,824,920
Stockholders' equity:
Common stock, $.005 par value:
Authorized: 50,000,000 shares Issued and outstanding: At June 30, 2008, and June 30, 2007, 7,259,622 shares		36,298		36,298
Capital in excess of par value		7,676,458		7,501,789
Accumulated other comprehensive loss		(281,849		-
Retained earnings		4,270,889		3,468,086
Total stockholders' equity		11,701,796		11,006,173
Total liabilities and stockholders' equity	$	20,000,804	$	21,139,302

See accompanying notes to these consolidated financial statements.

F-45

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED JUNE 30, 2008 AND 2007

	Year Ended
	June 30,
	2008			2007
Revenues:
Oil and gas sales	$	5,390,367		$	4,418,231
Operating expenses:
Oil and gas production		1,463,415			837,155
Accretion, and depreciation, depletion and amortization		2,451,417			2,018,550
Selling, general and administrative		621,463			850,847
Total operating expenses		4,536,295			3,706,552
Income from operations		854,072			711,679
Other income (expenses)
Interest and other income		117,354			136,411
Interest and other (expenses)		(63,678	)		(36,709	)
Gain (loss) on investments		4,834			717,878
Gain on sale of equipment		-			12,000
Total other income (expenses)		58,510			829,580
Income before income taxes		912,582			1,541,259
Provision for income taxes		(109,779	)		(615,990	)
Net income	$	802,803		$	925,269
Basic net income per share	$	0.11		$	0.13
Diluted net income per share	$	0.11		$	0.13
Weighted average number of common shares outstanding used to calculate basic net income per share :		7,259,622			7,213,992
Effect of dilutive securities:
Equity based compensation		113,455			166,778
Weighted average number of common shares outstanding used to calculate diluted net income per share :		7,373,077			7,380,770

See accompanying notes to these consolidated financial statements.

F-46

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED June 30, 2008 and 2007

	Common Stock
	Shares			Par Value			APIC			Accumulated (Deficit) Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Deferred Compensation			Total Equity
Balances at July 1, 2006		7,094,641		$	35,473		$	7,283,914		$	2,900,798		$	-		$	(119,233	)	$	10,100,952
Options exercised by employees		167,000			835			94,355			-			-			-			95,190
Stock forfeited by employees		(2,019	)		(10	)		(9,680	)		-			-			-			(9,690	)
Compensation expense per FAS 123R		-			-			133,200			-			-			-			133,200
Amortization of deferred compensation		-			-			-			-			-			119,233			119,233
Payment of cash dividends		-			-			-			(357,981	)		-			-			(357,981	)
Net income		-			-			-			925,269			-			-			925,269
Balances at June 30, 2007		7,259,622		$	36,298		$	7,501,789		$	3,468,086		$	-		$	-		$	11,006,173
Compensation expense per FAS 123R		-			-			174,669			-			-			-			174,669
Unrealized loss on marketable securities		-			-			-			-			(281,849	)		-			(281,849	)
Net income		-			-			-			802,803			-			-			802,803
Balances at June 30, 2008		7,259,622		$	36,298		$	7,676,458		$	4,270,889		$	(281,849	)	$	-		$	11,701,796

See accompanying notes to these consolidated financial statements.

F-47

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 2008 AND 2007

	Year Ended June 30,
	2008			2007
Cash Flows from Operating Activities:
Net income	$	802,803		$	925,269
Adjustments to reconcile net income to net cash provided by operating activities:
Accretion and depreciation, depletion, and amortization		2,451,417			2,018,550
Deferred income taxes		252,888			615,990
Amortization of deferred compensation		-			119,233
Compensation expense related to stock options granted		174,669			133,200
Realized (gain) on marketable securities		-			(559,949	)
Unrealized (gain) on marketable securities		-			(157,930	)
Proceeds from sale of marketable securities		-			599,921
(Gain) on sale of vehicle		-			(12,000	)
Changes in assets and liabilities:
(Increase) decrease in current assets other than cash, cash equivalents, and short-term marketable securities		(156,775	)		218,996
Increase (decrease) in current liabilities other than notes payable and asset retirement obligation		(1,770,323	)		(1,358,636	)

Net Cash Provided by Operating Activities		1,754,679			2,542,644

Cash Flows from Investing Activities:
Additions to oil and gas properties		(3,662,878	)		(4,018,136	)
Sales of securities		19,930			-
(Purchases) of securities		(300,000	)		-
Producing oil and gas properties purchased		-			(1,450,000	)
Additions to property and equipment		-			(89,425	)
Sale of property and equipment		1,140			12,000

Net Cash (Used in) Investing Activities		(3,941,808	)		(5,545,561	)

Cash Flows from Financing Activities:
Proceeds from exercise of stock options		-			85,500
Proceeds from issuance of long-term debt		-			975,000
Payment of long-term debt		(275,000	)		(108,333	)
Payment of cash dividends		-			(357,981	)

Net Cash Provided by (Used in) Financing Activities		(275,000	)		594,186

Net Increase (Decrease) in Cash and Cash Equivalents		(2,462,129	)		(2,408,731	)

Cash and Cash Equivalents, beginning of year		4,057,279			6,466,010

Cash and Cash Equivalents, end of year	$	1,595,150		$	4,057,279

See accompanying notes to these financial statements

F-48

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED JUNE 30, 2008 AND 2007

(Continued)

Supplemental disclosures of cash flow information:
Interest paid	$	63,678	$	30,093

Income taxes paid	$	800	$	800

Supplemental non-cash activity
Increase in asset retirement obligation	$	223,782	$	116,602
Notes payable assumed	$	-	$	375,000

See accompanying notes to these consolidated financial statements.

F-49

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Aspen Exploration Corporation (the “Company” or “Aspen”) was incorporated under the laws of the State of Delaware on February 28, 1980 for the primary purpose of acquiring, exploring and developing oil and gas properties. The Company is currently engaged primarily in the exploration and development of oil and gas properties in California and has a significant working interest in oil wells in the Poplar Field of northern Montana.

Oil and Gas Exploration and Development.The major emphasis has been participation in the oil and gas segment acquiring interests in producing oil or gas properties and participating in drilling operations. The Company engages in a broad range of activities associated with the oil and gas business in an effort to develop oil and gas reserves. With the assistance of management, independent contractors retained from time to time by Aspen, and, to a lesser extent, unsolicited submissions, the Company has identified and will continue to identify prospects believed to be suitable for drilling and acquisition. The Company’s primary area of interest is in the state of California where the Company has acquired a number of interests in oil and gas properties; in 2008, we acquired a working interest in 84 oil wells in the State of Montana, all as described below in more detail. In addition, the Company also acts as operator for a number of our producing wells and receives management fees for these services, which serve to offset our selling, general, and administrative expenses.

A summary of the Company's significant accounting policies follows:

Consolidated Financial Statements

The consolidated financial statements include the Company and its wholly-owned subsidiary, Aspen Gold Mining Company. Significant intercompany accounts and transactions, if any, have been eliminated. The subsidiary is currently inactive.

Cash and Cash Equivalents

For statement of cash flows purposes, short-term investments with original maturities of three months or less are considered to be cash equivalents. Cash restricted from use in operations beyond three months is not considered cash equivalents.

Management's Use of Estimates

Accounting principles generally accepted in the United States of America require certain estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent liabilities at the date of the financial statements and reported amounts of revenues and expenses to be made. Actual results could differ from those estimates. The Company’s significant estimates include estimated life of long-lived assets, use of reserves in the estimation of depletion of oil and gas properties, impairment of oil and gas properties, asset retirement obligation abilities, and income taxes.

The mining and oil and gas industries are subject, by their nature, to environmental hazards and cleanup costs for which the Company carries catastrophe insurance. At this time, there is no known substantial costs from environmental accidents or events for which the Company may be currently liable. In addition, the oil and gas business makes it vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices and estimated reserves. Price declines reduce the estimated quantity of proved reserves and increase annual depletion expense (which is based on proved reserves).

F-50

NOTE 1 -SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES(Continued)

Impairment of Long-Lived Assets

Long-lived assets and identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the expected undiscounted future cash flow from the use of the assets and their eventual disposition is less than the carrying amount of the assets, an impairment loss is recognized and measured using the asset’s fair value or discounted cash flows.

Financial Instruments

The carrying value of current assets and liabilities reasonably approximates their fair value due to their short maturity periods.

Investments in Debt and Equity Securities

Prior to the beginning of the current fiscal year, the Company classified all investments as Trading Securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. These securities were marked to market each period with the realized and unrealized gain or loss recorded in the statement of operations. The unrealized holding gain or loss at the date of the transfer (July 1, 2007), to the classification as available for sale, as described below, has already been recognized in earnings and shall not be reversed.

During the first quarter, management reassessed the appropriateness of the classification of the securities held, and determined that due to the sufficiency of the Company’s cash flows to finance current operations and budgeted expenditures, the Company will hold investments until such time it determines there may be a need to sell those securities, or the company determines a sale to be in its best interest. Consequently, as of July 1, 2007, Management determined the securities are more appropriately classified as available for sale, and changes in the fair value of the securities are reported as a separate component of shareholders’ equity until realized. Gains and losses are no longer a component of the Company’s Statement of Operations. Aspen uses the specific identification method to determine the cost of securities sold.

At June 30, 2008, the fair value of securities available for sale was $930,818. The net unrealized holding (loss) reported as a separate component of shareholders’ equity during the twelve months ended June 30, 2008, on securities still held as of June 30, 2008, was ($281,849), net of income tax of ($187,888).

Oil and Gas Properties

The Company follows the "full-cost" method of accounting for its oil and gas properties. Under this method, all costs associated with property acquisition, exploration and development activities, are capitalized within one cost center. No gains or losses are recognized on the receipt of prospect fees or on the sale or abandonment of oil and gas properties, unless the disposition of significant reserves is involved.

Depletion and amortization of our full-cost pool is computed using the units-of-production method based on proved reserves as determined annually by the Company and independent petroleum engineer. Capitalized costs related to unproved and developmental properties are immaterial as of June 30, 2008 and 2007, and are included in the amortization computation. An additional depletion provision in the form of a valuation allowance is made if the costs incurred on oil and gas properties, or revisions in reserve estimates, cause the total capitalized costs of oil and gas properties in the cost center to exceed the capitalization ceiling. The capitalization ceiling is the sum of (1) the present value of our future net revenues from estimated production of proved oil and gas reserves applicable to the cost center (using a 10% discount factor) plus (2) the lower of cost or estimated fair value of our cost center's unproved properties less (3) applicable income tax effects. The valuation allowance was $281,720 at June 30, 2008 and 2007 (Note 6). The Company has adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” Prior to adopting Statement 143, in calculating the full cost ceiling, Aspen reduced the expected future revenues from proved oil and gas reserves by the estimated future expenditures to be incurred in developing and producing such reserves discounted using a specified factor. While expected future cash flows related to the asset retirement obligation (ARO) were included in the calculation of the ceiling test, no associated asset was recorded. Under Statement 143, Aspen must recognize a liability for an asset retirement obligation at fair value in the period in which the obligation is incurred. The company also must initially capitalize the associated asset retirement costs by increasing long-lived oil and gas assets by the same amount as the liability. Any asset retirement costs capitalized pursuant to Statement 143 are subject to the full cost ceiling limitation under Rule 4-10(c)(4) of Regulation S-X.

F-51

NOTE 1 -SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES(Continued)

Oil and Gas Properties(Continued)

All capitalized costs are depleted on a composite units-of-production method based on estimated proved reserves attributable to the oil and gas properties owned by Aspen. Depletion and amortization expense was $2,396,083 and $1,964,504 for the years ended June 30, 2008 and 2007, respectively. Depletion expense per equivalent unit of production (MCFe) was $3.65 and $3.25 for 2008 and 2007, respectively.

Property and Equipment

Depreciation and amortization of property and equipment are expensed in amounts sufficient to relate the expiring costs of depreciable assets to operations over estimated service lives, principally using the straight-line method. Estimated service lives range from three to eight years. When assets are sold or otherwise disposed of, the cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is reflected in operations in the period realized. Depreciation expense was $21,266 and $54,046 for the years ended June 30, 2008 and 2007, respectively.

Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount. We do not have any off-balance-sheet credit exposure related to our customers. Aspen assesses credit risk and allowance for doubtful accounts on a customer specific basis. Aspen’s policy is not to grant long-term credit to customers, and to deal only with customers well-known in the oil and gas industry and with sufficient financial capability to meet its obligations. At June 30, 2008, except for immaterial amounts, all of its production was sold to 3 customers. Each of these customers is well known in the industry and to management and management believes each customer to have sufficient financial capability. As of June 30, 2008 and 2007, Aspen does not have an allowance for doubtful accounts.

Revenue Recognition

Sales of oil and gas production are recognized at the time of delivery of the product to the purchaser.

Earnings Per Share

The Company follows Statement of Financial Accounting Standards (“SFAS”) No. 128, addressing earnings per share. SFAS No. 128 established the methodology of calculating basic earnings per share and diluted earnings per share. The calculations differ by adding any instruments convertible to common stock (such as stock options, warrants, and convertible preferred stock) to weighted average shares outstanding when computing diluted earnings per share.

F-52

NOTE 1 -SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES(Continued)

Earnings Per Share(Continued)

The following is a reconciliation of the numerators and denominators used in the calculations of basic and diluted earnings per share.

	Year Ended June 30,
	2008						2007
					Per						Per
	Net				Share		Net				Share
	Income		Shares		Amount		Income		Shares		Amount
Basic Earnings Per Share:
Net income and share amounts	$	802,803		7,259,622	$	0.11	$	925,269		7,213,992	$	0.13
Effect of Dilutive Securities:
Stock Options		-		113,455		-		-		166,778		-
Diluted Earnings Per Share:
Net income and assumed share conversion	$	802,803		7,373,077	$	0.11	$	925,269		7,380,770	$	0.13

Income Taxes

The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time. The Company adopted FASB interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes, effective July 1, 2007 . Fin 48 requires that amounts recognized in the Balance Sheet related to uncertain tax positions be classified as a current or noncurrent liability, based upon the expected timing of the payment to a taxing authority. The Company had no material uncertain tax positions as of June 30, 2008 or 2007.

The total future deferred income tax liability is extremely complicated for any energy company to estimate due in part to the long-lived nature of depleting oil and gas reserves and variables such as product prices. Accordingly, the liability is subject to continual recalculation, revision of the numerous estimates is required, and may change significantly in the event of such things as major acquisitions, divestitures, product price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.

See Note 3 below.

Equity-Based Compensation

We adopted SFAS No. 123(R) beginning July 1, 2006. Prior to July 1, 2006, the Company accounted for these plans under the recognition and measurement provisions of Accounting Principles Board ("APB") Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, as permitted by Statement of Financial Accounting Standards("SFAS") No. 123, Accounting for Stock-Based Compensation. No stock-based employee compensation expense was recognized in the Company's Consolidated Statement of Operations prior to July 1, 2006, as all options granted under the Company's stock-based compensation plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective July 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123 (R), Share Based Payment, using the modified-prospective transition method as described in SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, compensation cost recognized in fiscal 2007 is the same as that which would have been recognized had the recognition provisions of Statement 123(R) been applied from its original effective date. See Note 2 below.

F-53

NOTE 1 –SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES(Continued)

Equity-Based Compensation (Continued)

The adoption of SFAS 123(R) resulted in stock compensation expense for the years ended June 30, 2008 and 2007 of $174,669 and $133,200, respectively, to income from continuing operations and income before income taxes. This expense reduced our basic and diluted earnings per share by approximately $0.24 and $0.18 for the year ended June 30, 2008.

Recently Issued Pronouncements

In September 2006, Statement of Financial Accounting Standards (SFAS) No. 157,Fair Value Measurementswas issued by the Financial Accounting Standards Board (FASB). This statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 will become effective for the Company’s fiscal year beginning after November 15, 2007, and the Company is currently assessing the potential impact of this Statement on its financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities, which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. This statement was effective beginning January 1, 2008 and did not have a material effect on the Company’s financial statements of this pronouncement.

In December 2007, FASB issued SFAS No. 160,Noncontrollnig Interests in Consolidated Financial Statements, which amends Accounting Research Bulletin (ARB) No. 51 and (1) establishes standards of accounting and reporting on noncontrolling interests in consolidated statements, (2) provides guidance on accounting for changes in the parent's ownership interest in a subsidiary, and (3) establishes standards of accounting of the deconsolidation of a subsidiary due to the loss of control. The amendments to ARB No. 51 made by SFAS No. 160 are effective for fiscal years (and interim period within those years) beginning on or after December 15, 2008. The Company is currently assessing the potential impact this statement on its financial statements.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which expands the information that a reporting entity provides in its financial reports about a business combination and its effects. This Statement establishes principles and requirements for how the acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.

F-54

NOTE 1 –SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES(Continued)

Recently Issued Pronouncements(Continued)

This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. Aspen may experience a financial statement impact depending on the nature and extent of any new business combinations entered into after the effective date of SFAS No. 141(R).

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities. Enhanced disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement will require the additional disclosures described above.

In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America (the GAAP hierarchy). This Statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. Aspen does not expect the adoption of SFAS 162 to have a material effect on our financial statements or related disclosures.

NOTE 2 – EQUITY COMPENSATION PLANS

Stock Options

Effective July 1, 2006, the Company adopted the fair value recognition provisions of Statement of Financial Accounting Standard 123(R) “Share-Based Payment” (“SFAS 123(R)”) using the modified prospective transition method. In addition, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107 “Share-Based Payment” (“SAB 107”) in March, 2005, which provides supplemental SFAS 123(R) application guidance based on the views of the SEC. Under the modified prospective transition method, compensation cost recognized for the year ended June 30, 2008 include: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of July 1, 2007, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted beginning July 1, 2007, based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R). In accordance with the modified prospective transition method, results for prior periods have not been restated.

Aspen has three stock option plans as of June 30, 2008, “Option Plan #2,” effective March 14, 2002, “Option Plan #3,” effective April 27, 2005, and “The 2008 Equity Plan”. There were an aggregate of 1,936,000 common shares reserved for issuance under our stock option plans. These plans provided for the issuance of 676,000, 260,000, and 1,000,000 common shares, respectively, pursuant to stock option exercises. The fair value of each option grant, as opposed to its exercise price, is estimated on the date of grant using the Black-Scholes option-pricing model. The options issued under the 2008 Option Plan were valued using with the following weighted average assumptions: no dividend yield, expected volatility of 58%, risk free interest rates of 2.25% and expected lives of 3.3 years. Expected volatility was calculated based upon actual historical stock price movements over the most recent periods through the date of issuance, equal to the expected option term. Expected pre-vesting forfeitures were assumed to be zero. The expected option term was calculated using the “simplified” method permitted by SAB 107.

F-55

NOTE 2 –EQUITYCOMPENSATION PLANS(Continued)

Stock Options(Continued)

Additionally, 10,000 options were granted to a non-employee director on September 11, 2006. The fair value of those options was estimated using the Black-Scholes option-pricing model with the following assumptions: no dividend yield, expected volatility of 73%, risk free interest rates of 4.97% and expected life of 5 years.

The following information summarizes information with respect to options granted under equity plans:

						Weighted-
						Average
				Weighted-		Remaining		Aggregate
	Number of			Average		Contractual		Intrinsic
	Shares			Exercise Price		Term		Value

Outstanding at July 1, 2006		502,000		$	1.55

Granted		10,000			3.70
Exercised		(167,000	)		0.57
Forfeited or expired		(115,000	)		1.76

Outstanding at June 30, 2007		230,000		$	2.26		2.28	$	333,500

Granted		775,000			2.14
Exercised		-			-
Forfeited or expired		(117,902	)		2.14

Outstanding at June 30, 2008		887,098		$	2.17		3.79	$	558,872

Exercisable at June 30, 2007		123,334		$	2.75		2.65	$	118,401

Exercisable at June 30, 2008		370,431		$	2.21		2.56	$	218,554

The grant-date fair value of options granted during the period was $702,929. No options were exercised during the period ending June 30, 2008.

F-56

NOTE 2 –EQUITY COMPENSATION PLANS(Continued)

Stock Options (Continued)

A summary of the status of the Company’s nonvested shares underlying the options outstanding as of June 30, 2008 and 2007, and changes during the years then ended are presented below:

				Weighted-
				Average
	Number of			Grant-Date
	Shares			Fair Value

Nonvested at July 1, 2006		256,666		$	1.85

Granted		-			-
Vested		(106,667	)		1.69
Forfeited		(43,333	)		2.67

Nonvested at June 30, 2007		106,666		$	1.69

Granted		775,000			0.91
Vested		(247,097	)		1.00
Forfeited		(117,902	)		0.91

Nonvested at June 30, 2008		516,667		$	0.91

The total compensation cost related to nonvested awards not yet recognized on June 30, 2008 is approximately $291,000, net of tax, and the weighted average period over which this cost is expected to be recognized is 2 years. The total fair value of options vested during the period was $691,872.

The following table summarizes information concerning outstanding and exercisable options as of June 30, 2008:

				Outstanding				Exercisable
				Weighted
				Average		Weighted				Weighted
				Remaining		Average				Average
Exercise		Number		Contractual		Exercisable		Number		Exercisable
Price		Outstanding		Life in Years (1)		Price		Exercisable		Price

$	0.57		50,000		0.13	$	0.57		50,000	$	0.57

	2.67		170,000		1.51		2.67		170,000		2.67

	3.70		10,000		3.20		3.70		10,000		3.70

	2.14		657,098		4.67		2.14		140,431		2.14

			887,098		3.79	$	2.17		370,431	$	2.21

⁽¹⁾The term of the option will be the earlier of the contractual life of the options or 90 days after the date the optionee is no longer an employee, consultant or director of the Company.

F-57

NOTE 2 –EQUITY COMPENSATION PLANS(Continued)

Stock Options (Continued)

No options were exercised during the current fiscal year.

NOTE 3 –INCOME TAXES

The Company recorded deferred income tax assets of $1,573,500 and $1,673,000, and deferred income tax liabilities of approximately $4,093,500 and $4,128,000 as of June 30, 2008 and 2007, respectively. The Company paid $800 in California state income taxes in fiscal 2008.

The deferred tax consequences of temporary differences in reporting items for financial statement and income tax purposes are recognized, if appropriate. Realization of future tax benefits related to the deferred tax assets is dependent on many factors, including the ability to generate taxable income within the carryforward period. The Company had approximately $219,500 in net operating loss carryforwards at June 30, 2007 expiring June 30, 2027, and an additional $494,500 at June 30, 2008, which will expire June 30, 2028. The Company has considered these factors in reaching our conclusion as to the valuation allowance for financial reporting purposes and believe it more likely than not that the benefit will be realized.

The income tax effect of temporary differences comprising the deferred tax assets and deferred tax liabilities on the accompanying balance sheets is the result of the following:

	2008			2007
Deferred tax assets:
NOL and percentage depletion carryforward	$	896,500		$	1,129,000
State income tax expense		341,000			292,000
Equity based compensation		99,500			54,000
Asset retirement obligation		236,500			198,000

		1,573,500			1,673,000

Deferred tax (liabilities):
Oil and gas properties		(3,959,500	)		(3,774,000	)
Property, plant, and equipment		(12,000	)		(12,000	)
Gain on Investments		(122,000	)		(342,000	)

		(4,093,500	)		(4,128,000	)

	$	(2,520,000	)	$	(2,455,000	)

A reconciliation between the statutory federal income tax rate and the effective rate of income tax expense for the two years ended June 30 is as follows:

	2008			2007

Statutory federal income tax rate		35	%		35	%
Statutory state income tax rate, net of federal benefit		5	%		6	%
Recognition of tax basis of properties		-27	%		-2	%
Blended State Rate Change/Other		-1	%		1	%

Effective rate		12	%		40	%

F-58

NOTE 3 –INCOME TAXES (Continued)

The provision for income taxes consists of the following components

	2008		2007

Current tax expense/(benefit)	$	44,779	$	342,000
Deferred tax expense		65,000		273,990
Total income tax provision	$	109,779	$	615,990

NOTE 4 –RELATED PARTY TRANSACTIONS

During fiscal 2008, the Company assigned the following overrides to employees:

	R.V. Bailey		R.A. Cohan		J.L. Shelton

	percent		percent		percent

Johnson unit 13		1.260000		1.260000		0.480000
SJDD 11-1		1.360000		2.000000		0.640000
Delta Farms 10		0.816000		1.200000		0.384000
Eastby 1-1		0.906661		1.333325		0.426664

The Company has an "Amended Royalty and Working Interest Plan" by which the Company, in its discretion, is able to assign overriding royalty interests or working interests in oil and gas properties or in mineral properties. This plan is intended to provide additional compensation to Aspen's personnel involved in the acquisition, exploration and development of Aspen's oil or gas or mineral prospects. Since the Company only assigns interests under the Amended Royalty and Working Interest Plan from properties that are unproven or exploratory, those interests are deemed to have no value and consequently Aspen recognizes no compensation expense and the employees recognize no income from the assignment. If drilling on such property occurs in the future and results in a well capable of production, the employees holding royalty interests will recognize income as royalty income is received.

R. V. Bailey, Chief Executive Officer and director of the Company, Robert A. Cohan, President and director of the Company, have working and royalty interests in certain of the California oil and gas properties operated by us. Mr. Bailey and Mr. Cohan purchased working interests from the Company amounts totaling $220,490 and $109,790, respectively, for the year ended June 30, 2008, and $263,690 and $131,250, respectively, for the year ended June 30, 2007. The related parties paid for their proportionate working interest share of all costs to acquire, develop and operate these properties on the same terms as other unaffiliated participants. Mr. Bailey and Mr. Cohan also received royalty interest payments totaling $102,927 and $145,873, respectively, for the year ended June 30, 2008, and $66,196 and $88,268, respectively, for the year ended June 30, 2007. These royalties relate to the royalties assigned to employees as described above, and the royalties that were assigned in prior years. As of June 30, 2008, working interests of Aspen and related parties in certain producing California properties are as set forth below (unaudited):

	Gross Wells		Net Wells
	Gas		Gas

Aspen Exploration		88		19.17
R. V. Bailey		67		2.14
R. A. Cohan		67		1.20
J.L. Shelton		52		0.12

F-59

NOTE 4 –RELATED PARTY TRANSACTIONS (Continued)

The Company has remaining advances from Messrs. Bailey and Cohan for working interests of $5,600 and $10,307, respectively, as of June 30, 2008 and $79,799 and $33,267 as of June 30, 2007, respectively, and are recorded in other current liabilities and accrued expenses in the accompanying balance sheets.

NOTE 5 –DIVIDENDS

Aspen paid a special dividend of $.05 per share on December 6, 2006 totaling $357,981 to shareholders of records as of November 20, 2006. No dividends were declared or paid during the fiscal year ended June 30, 2008.

NOTE 6 – OIL AND GAS ACTIVITIES

Capitalized Costs

Capitalized costs associated with oil and gas producing activities are as follows:

	June 30,
	2008			2007

Proved properties	$	23,677,355		$	19,802,843

Accumulated depreciation, depletion, and amortization		(10,197,746	)		(7,801,663	)
Valuation allowance		(281,720	)		(281,720	)

		(10,479,466	)		(8,083,383	)
Net capitalized costs	$	13,197,889		$	11,719,460

At the date of acquisition of the properties, certain undeveloped properties were also acquired. The value assigned to these properties was nominal as it was determined the fair value of the properties was immaterial at the time of acquisition.

Results of Operations

Results of operations for oil and gas producing activities are as follows:

	Year Ended June 30,
	2008			2007

Revenues	$	5,390,367		$	4,418,231
Production costs		(1,463,415	)		(837,155	)
Depreciation, depletion and accretion		(2,451,415	)		(2,018,550	)

Results of operations (excluding corporate overhead)	$	1,475,537		$	1,562,526

Acquisition, Exploration and Development Costs
	2008			2007

Property acquisition costs net of divestiture proceeds	$	30,000		$	1,450,000
Exploration		3,632,878			4,018,136
Development		-			-

Total before asset retirement obligation	$	3,662,878		$	5,468,136

F-60

NOTE 6 – OIL AND GAS ACTIVITIES (Continued)

Results of Operations (Continued)

Total including asset retirement obligation:

	Year Ended June 30,
	2008		2007
Acquisitions	$	30,000	$	109,250
Exploration		3,844,512		5,418,951
Development		-		-

Total	$	3,874,512	$	5,528,201

Fees charged by Aspen to operate the properties totaled approximately $607,000 and $513,000 for the years ended 2008 and 2007, respectively, and are recorded as reductions to SG&A in the accompanying Statement of Operations.

Unaudited Oil and Gas Reserve Quantities

The following unaudited reserve estimates presented as of June 30, 2008 and 2007 were prepared by an independent petroleum engineer. There are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, reserve estimates of new discoveries that have little production history are more imprecise than those of properties with more production history. Accordingly, these estimates are expected to change as future information becomes available.

Proved oil and gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., process and costs as of the date the estimate is made.

Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

F-61

NOTE 6 – OIL AND GAS ACTIVITIES (Continued)

Unaudited Oil and Gas Reserve Quantities (Continued)

Unaudited net quantities of proved developed reserves of crude oil (including condensate) and natural gas (all located within the United States) are as follows:

	(Bbls)			(MCF)
	(in thousands)

Estimated quantity, July 1, 2006		2			2,751

Revisions of previous estimates		-			(326	)
Acquisitions		132			-
Discoveries		-			874
Production		(4	)		(598	)

Estimated quantity, June 30, 2007		130			2,701

Revisions of previous estimates		72			(337	)
Discoveries		-			383
Production and Sales		(11	)		(596	)

Estimated quantity, June 30, 2008		191			2,151

Changes in Proved Reserves

	Developed		Developed Non-
Proved Reserves at Year End	Producing		Producing		Total
			(in thousands)
Oil (Bbls)
June 30, 2008		158		33		191
June 30, 2007		99		31		130

Gas (MCF)
June 30, 2008		889		1,262		2,151
June 30, 2007		959		1,742		2,701

Unaudited Standardized Measure

The following information has been developed utilizing procedures prescribed by SFAS 69 “Disclosures About Oil and Gas Producing Activities” and based on crude oil and natural gas reserves and production volumes estimated by the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative or realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

Future cash inflows were computed by applying year-end prices of oil and gas to the estimated future production of proved oil and gas reserves. The future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to Aspen’s proved oil and gas reserves and the tax basis of proved oil and gas properties and available net operating loss carryforwards. Discounting the future net cash inflows at 10% is a method to measure the impact of the time value of money.

F-62

NOTE 6 – OIL AND GAS ACTIVITIES (Continued)

Unaudited Standardized Measure (Continued)

	June 30,
	2008			2007
	(in thousands)

Future cash inflows	$	46,843		$	26,015
Future production costs		(22,108	)		(4,534	)
Future development costs		(229	)		(306	)
Future income tax expense		(8,658	)		(8,628	)

Future cash flows		15,848			12,547

10% annual discount for estimated timing of cash flows		(5,579	)		(4,513	)

Standardized measure of discounted future net cash	$	10,269		$	8,034

The following presents the principal sources of the changes in the standardized measure of discounted future net cash flows:

	Years Ended June 30,
	2008			2007
	(in thousands)

Standardized measure of discounted future net cash flows,
beginning of year	$	8,034		$	5,104

Sales and transfers of oil and gas produced, net of production costs		(3,927	)		(3,581	)
Net changes in prices and production costs and other		2,246			1,846
Net change due to discoveries		1,773			2,625
Acquisition of reserves		-			3,129
Revisions of previous quantity estimates		71			(269	)
Development costs incurred		889			306
Accretion of discount		803			1,306
Net change in income taxes		539			(2,130	)
Other		(159	)		(302	)

		2,235			2,930

Standardized measure of discounted future net cash flows,
end of year	$	10,269		$	8,034

Net changes in prices and production costs of $2.2 million were the result of an increase in the price received for gas at year end which was offset slightly by an increase in operating costs associated with more producing gas wells in 2008 than in 2007. The revision of previous estimates of $71,000 was the result of reducing recoverable reserves of gas by approximately 337,000 MCF, and an increase in oil reserves of 72,000 barrels. All adjustments were based on performance reviews of individual wells.

F-63

NOTE 7 –PROPERTY ACQUISITIONS

In February 2007, the Company purchased from Nautilus Poplar, LLC, a non-operating working interest in certain oil producing assets encompassing 22,600 acres in the East Poplar Unit and the Northwest Poplar Field in Roosevelt County, Montana located in the Williston Basin. These properties contain a total of 33 producing oil wells, and 7 salt-water disposal wells. Current production is 230 gross BOPD from the Charles “B” reservoir. Through December 2007, Aspen was obligated to pay 12.5% of the expenses of operations for a 10% working interest. Since Aspen’s investment did not reach payout as of January 1, 2008, Aspen’s expense obligation was reduced to 10%. At payout, Aspen’s working interest will proportionately be reduced also. As of June 30, 2008, there remains $1,315,211 until Aspen reaches payout, based on total revenues received through June 30, 2008 of $984,590. Commencing February 2008, Aspen (and the other working interest participants) agreed that the operator could retain 60% of the cash flow from the producing wells (after deduction of royalties, taxes, expenses and loan payment) for capital projects, geology and engineering (amounting to a total of $96,250 to Aspen’s account as of June 30, 2008). The operator has used these funds for capital expenses, workovers and recompletions. Additionally, in May 2008 Aspen amended its participation agreement in the Poplar Unit to separately market and deal with the “deeper rights,” oil and gas rights below the base of the Mission Canyon Formation and to grant one of the participants the right to seek to farmout the deeper rights. To the extent that Aspen has available capital and has identified other appropriate drilling or exploration opportunities, Aspen may participate in the drilling of additional wells.

NOTE 8 –ASSET RETIREMENT OBLIGATION

The Company has adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires the Company to recognize an estimated liability for the plugging and abandonment of all oil and gas wells. A liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production. The increase in the asset will be amortized over time and the Company will recognize accretion expense in connection with the discounted liability over the remaining life of the respective well. Any asset retirement costs capitalized pursuant to Statement 143 are subject to the full cost ceiling limitation under Rule 4-10(c)(4) of Regulation S-X. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including: the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. In 2008, we reassessed our estimate as costs have increased due to demand for these services, resulting in an increase in the ARO balance at year end.

Under SFAS 143, the following table summarizes the change in abandonment obligation for the years ended June 30:

	2008			2007

Beginning balance at July 1	$	486,653		$	394,623
Liabilities incurred		80,073			189,256
Liabilities settled		(9,225	)		(30,416	)
Accretion expense		34,068			31,965
Revision to estimate		140,786			(98,775	)

Ending balance at June 30	$	732,355		$	486,653

F-64

NOTE 9 –LONG-TERM DEBT

In January 2007, Aspen borrowed $600,000 from Wells Fargo Bank, NA pursuant to a promissory note payable over thirty-six months to partially finance the acquisition of the Poplar Field discussed in Note 7. Interest on the note is charged at LIBOR plus 2.25% . Aspen subsequently entered into an interest rate swap agreement with Wells Fargo Bank, which fixes the interest rate on the note at 8.10% . Principal of $16,667 plus interest payments are due monthly beginning February 15, 2007 and continuing to January 15, 2010. Collateral consists of a blanket filing on Accounts Receivables. At June 30, 2008 the outstanding balance on the note was $316,667, of which $200,000 is classified as current.

The Wells Fargo note contains restrictive covenants which, among other things, require us to maintain a certain “Net Worth” defined as total stockholder’s equity of not less that $9,000,000 at any time, net income after taxes not less than $1,000 on an annual basis and an EBITDA ratio, as defined. We are currently in compliance with our covenants to Wells Fargo. At June 30, 2008, the outstanding balance was $316,667, of which $200,000 is classified as current.

In February 2007, as part of the Poplar acquisition, Aspen agreed to be responsible for 12.5% of a $3,000,000 loan obtained by Nautilus in connection with the purchase of the Poplar Field assets. Nautilus Poplar, LLC obtained the loan from the Jonah Bank of Wyoming, as lender. Aspen’s share of this loan is $375,000 plus interest at a rate of 9.0%, and Aspen is subject to the repayment schedule that Nautilus Poplar negotiated and to the other terms and conditions of the loan agreement as fully as if Aspen were a party to the loan agreement. Aspen’s share of principal payments of $6,250 plus interest is due monthly through February 25, 2009. At June 30, 2008, the outstanding balance was $275,000, all of which is classified as current.

Required principal payments on all long term debt through maturity are as follows:

Year Ended
June 30,	Total
2009	$	475,000
2010		116,667
	$	591,667

NOTE 10 –MAJOR CUSTOMERS

Aspen derived in excess of 10% of revenue from its major customers as follows:

	Company
Year Ended	A			B
June 30, 2008		33	%		61	%
June 30, 2007		15	%		77	%

NOTE 11 – CONCENTRATION OF CREDIT RISK

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of cash and cash equivalents, accounts receivable and short-term investments. While as of June 30, 2008 the Company has approximately $3 million in excess of the Federal Deposit Insurance Corporation $100,000 limit at one bank, the Company places cash and cash equivalents with high quality financial institutions in order to limit credit risk. Concentrations of credit risk with respect to accounts receivable are distributed across unrelated businesses and individuals, with the exception of two major gas purchasers and one investor in our wells, who normally settle within 25 days of the previous month’s gas purchases. The Company believes its exposure to credit risk is minimal.

Cash equivalents are invested through a quality national brokerage firm and a major regional bank. The cash equivalents consist of liquid short-term investments. The Securities Investor Protection Corporation insures the Fund’s accounts at this brokerage firm and a commercial insurer up to the total amount held in the account.

F-65

NOTE 12 –COMMITMENTS AND CONTINGENCIES

In January 2007 Aspen entered into a venture to explore for gold in Alaska with Hemis Corporation, with offices in Las Vegas, Nevada, whereby Hemis will provide all funding and be the operator of a venture to carry out permit acquisition and exploration for commercial quantities of gold. If such deposits are found, Hemis intends to produce and sell the gold as well as any other commercially valuable minerals that may occur with the gold. Hemis has commenced work to obtain permits for the project.

Hemis paid Aspen $50,000 in January 2007 and another $50,000 in August 2007. Hemis was obligated to pay Aspen another $50,000 on or before September 1, 2008 and on each anniversary date until production of gold begins. Hemis did not make the 2008 payment to Aspen, and Aspen have provided notification to Hemis of Aspen’s intention to terminate that agreement. The agreement will be terminated unless Hemis cures the payment default and certain other defaults within the 30 day notice period. Aspen does not know if Hemis will cure the payment default or contest the existence of the other defaults that Aspen alleged.

The Company has entered into a series of gas sales contracts with Enserco and Calpine Producer Services, L.P. In each of the contracts, the purchasers were required to purchase the stated quantities at stated prices, less transportation and other expenses. The contracts contain monetary penalties for non-delivery of the gas. The following table sets forth some additional information about those contracts:

Date of Contract	Purchaser	Term	Fixed Price		Quantity

July 31, 2006	Enserco	11/1/2006-3/31/2007		$10.15 per MMBTU	2,000 MMBTU per day
October 4, 2006	Enserco	12/1/2006-3/31/2007		$7.30 per MMBTU	2,000 MMBTU per day
January 30, 2007	Enserco	4/1/2007-10/31/2007		$7.65 per MMBTU	2,000 MMBTU per day
April 12, 2007	Enserco	11/1/2007-3/31/2008		$9.02 per MMBTU	2,000 MMBTU per day
February 15, 2008	Enserco	4/1/2008-10/31/2008		$8.61 per MMBTU	1,000 MMBTU per day
February 21, 2008	Enserco	4/1/2008-10/31/2008		$8.81 per MMBTU	1,000 MMBTU per day
February 26, 2008	Calpine	4/1/2008-10/31/2008		$8.80 per MMBTU	500 MMBTU per day

Aspen expects to have sufficient gas available for delivery to Enserco and Calpine from anticipated production from our California fields.

Aspen’s sales of natural gas under the Enserco and Calpine Contracts qualify for the “Normal Purchases and Normal Sales” exception in paragraph 10(b) of FAS 133. The contracts contain net settlement provisions should the Company fail to deliver natural gas when required. Those provisions are mutual and establish the sole and exclusive remedy of the parties in the event of a breach of a firm obligation to deliver or receive natural gas. The provisions are summarized as follows:

(i)

In the event of a breach by Aspen on any day, Aspen would be required to pay Enserco or Calpine an amount equal to the positive difference, if any, between the purchase price and transportation costs paid by Enserco purchasing replacement natural gas and the amount of Aspen’s default; or

(ii)

In the event of a breach by Enserco or Calpine on any day, they must pay to Aspen any losses incurred by Aspen after attempting the resale of the natural gas; or

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NOTE 12 –COMMITMENTS AND CONTINGENCIES(Continued)

(iii)

In the event that Enserco or Calpine have used commercially reasonable efforts to replace the natural gas not delivered by Aspen, or Aspen has used commercially reasonable efforts to sell the undelivered natural gas to a third party and no such replacement or sale is available, the sole and exclusive remedy of the performing party shall be any unfavorable difference between the contract price and the spot price, adjusted for transportation.

The natures of the penalties are based on the current market prices and therefore are variable. Aspen has met its obligations under the contracts since the inception of the contracts, and expects to continue to have sufficient gas available for delivery to fulfill current contractual delivery quantity obligations from anticipated production from the Company’s California fields.

The Company has the following commitments for exploration in the next fiscal year:

			Drilling		Completion &
Area	Wells		Costs		Equipping Costs		Total

West Grimes Gas Field
Colusa County, CA		2	$	480,000	$	288,000	$	768,000

Total Expenditure		2	$	480,000	$	288,000	$	768,000

The proposed drilling budget only includes the wells that we have already budgeted. It can be expected that Aspen will drill several wells in addition to the two included in our current budget. Aspen has not identified locations for those additional drilling activities, however.

Employment Contracts and Termination of Employment and Change in Control Arrangements

Mr. Bailey:Effective May 1, 2003 the Company entered into an employment agreement with Chairman of the Board, R. V. Bailey. Some of the pertinent provisions include an employment period ending May 1, 2009, the title of Vice President subject to the general direction of the President, Robert A. Cohan, and the Board of Directors of Aspen. Mr. Bailey’s salary will be $45,000 per year from May 1, 2003 to December 31, 2006 and $60,000 per year from January 1, 2007, ending May 1, 2009. Mr. Bailey will also participate in Aspen’s stock options and royalty interest programs. During the term of the agreement, the Company has agreed to pay Mr. Bailey a monthly $1,700 allowance to cover such items as prescriptions, medical and dental coverage for himself and his dependents and other expenses not covered in the agreement.

Mr. Bailey will continue to use the Company vehicle and may trade the current vehicle for a similar vehicle of his choice prior to June 30, 2007. A vehicle was purchased for Mr. Bailey in 2006. During 2007 or thereafter, Mr. Bailey may purchase the vehicle for $500.

The Company may terminate this agreement upon Mr. Bailey’s death by paying his estate all compensation that had or will accrue to the end of the year of his death plus $75,000. Should Mr. Bailey become totally and permanently disabled, the Company will pay Mr. Bailey one half of the salary and benefits set forth in our agreement with him for the remainder of the term of the agreement.

Mr. Cohan:Aspen and Robert A. Cohan entered into an employment agreement dated January 1, 2003, as amended on April 22, 2005 (the “Agreement”). The Agreement was for an initial three-year term and

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NOTE 12 –COMMITMENTS AND CONTINGENCIES(Continued)

Employment Contracts and Termination of Employment and Change in Control Arrangements (Continued)

was amended in April 2005. As amended, the term of the agreement ends on December 31, 2008, but would continue thereafter on a year-to-year basis unless terminated by either party. Currently under the Agreement we pay Mr. Cohan an annual salary of $160,000 (which we will continue to pay through December 31, 2008). Aspen also offers Mr. Cohan health insurance, cost reimbursement, and certain other benefits.

As reported in January 2008, Mr. Cohan suffered a stroke and was unable to continue to perform his duties as chief executive officer and chief financial officer of Aspen. As a result, Messrs. R.V. Bailey and Kevan Hensman assumed these duties. Mr. Cohan retained the title of president, and has been working with Messrs. Bailey and Hensman and Aspen’s other employees and consultants as able to ensure that Aspen’s oil and gas operations continue. Although Mr. Cohan has provided substantial continuing assistance to Aspen, he has been unable to resume his duties as chief executive officer and chief financial officer. Inasmuch as Aspen is exploring strategic alternatives as described above, the board of directors, including Mr. Cohan, concurred that it was appropriate to provide notice to Mr. Cohan that his employment agreement would not be renewed when it expires on December 31, 2008.

Therefore, on September 4, 2008, Aspen notified Mr. Cohan that his employment agreement would not be renewed when it expires on December 31, 2008. This notification does not terminate Mr. Cohan’s employment either now or on December 31, 2008, but merely advises him that his employment agreement will not be renewed. Mr. Cohan retains the title of president. The Board of Directors determined that it would consider the continuing employment status of all of its officers later in the year. Aspen will not be obligated to pay any penalties for not renewing the Agreement.

Operating Leases

The Company maintains office space in Denver, Colorado, our principal office, and Bakersfield, California. The Denver office consists of approximately 1,108 square feet with an additional 750 square feet of basement storage. Aspen entered into a one year lease May 1, 2008 and will continue thereafter on a month-to-month basis for $1,261 per month. The Bakersfield, California office has 546 square feet and lease payments are $901 to $934 over the term of the lease, which expired July 31, 2008 and was extended to December 31, 2008. Rent expense for the years ended June 30, 2008 and 2007 were $26,581 and $26,264, respectively.

NOTE 13 – EMPLOYEE BENEFIT PLANS

Defined Contribution Plan

The Company has adopted a Profit-Sharing 401(k) Plan, which took effect July 1, 1990. All employees are eligible to participate in this Plan immediately upon being hired to work at least 1,000 hours per year and attained age 21. Aspen makes matching contributions equal to 50% of the participant’s elective deferrals. Those contributions totaled $30,250 and $30,125 for the years ended 2008 and 2007, respectively.

Medical Benefit Plan

For the fiscal years ended June 30, 2008 and 2007, the Company had a policy of reimbursing employees for medical expenses incurred but not covered by the paid medical insurance plan. Expenses reimbursed for fiscal 2008 and fiscal 2007 were $24,108 and $22,947, respectively. As of June 30, 2008 and 2007 there were no accruals for reimbursement of medical expenses. Under the terms of a revised employment agreement with Mr. Bailey, effective May 1, 2003 he will be responsible for his own medical insurance premiums and will no longer be reimbursed excess medical expenses.

F-68

NOTE 14 –SUBSEQUENT EVENTS

At June 30, 2008, the Company held investments in securities totaling $930,818. Subsequent to our fiscal year end, the fair market value of our trading portfolio has decreased approximately $350,000 as of September 15, 2008, due to unfavorable market conditions. The Company does not have enough information available to ascertain whether this decline in fair value is an other than temporary impairment.

On September 4, 2008, Aspen issued a press release announcing that Aspen has decided to investigate strategic alternatives, including the possibility of selling Aspen’s assets or considering another appropriate merger or acquisition transaction, and plans to open a data room where interested persons may review certain information. Aspen has entered into an agreement with Brian Wolf, a California-licensed mineral, oil and gas broker and consulting geologist, to assemble and operate the data room. Any transaction may require shareholder approval; such approval, if required, will be sought in accordance with the requirements of the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder.

As of the date of its Annual Report Aspen had not received any offer from any person for an asset acquisition, merger, or other business combination. In a press release on November 24, 2008, Aspen reported that it had received one or more offers. Aspen cannot offer any assurance that it will receive an acceptable offer from any person for an asset acquisition, merger, or other business combination. Further, Aspen may later determine that it is in the best interest of its shareholders to investigate other forms of business alternatives or to continue and expand existing business operations with existing or new management. In the meantime, Aspen will continue to carry on its business operations in the normal course.

F-69

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2008			June 30, 2008
	(unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	1,748,667		$	1,595,150
Marketable securities		410,673			930,818
Accounts and trade receivables		1,770,131			2,287,519
Other current assets		41,244			39,474

Total current assets		3,970,715			4,852,961

Property and equipment
Oil and gas property		23,719,323			23,677,355
Support equipment		183,374			183,374

		23,902,697			23,860,729
Accumulated depletion and impairment - full cost pool		(10,994,466	)		(10,479,466	)
Accumulated depreciation - support equipment		(75,889	)		(70,570	)

Net property and equipment		12,832,342			13,310,693

Other assets:
Deposits		263,650			263,650
Deferred income taxes		1,488,500			1,573,500

Total other assets		1,752,150			1,837,150

Total assets	$	18,555,207		$	20,000,804

(Statement Continues)

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

F-70

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

	September 30, 2008			June 30, 2008
	(unaudited)

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	1,468,345		$	2,260,611
Other current liabilities and accrued expenses		494,655			620,875
Notes payable - current portion		453,180			475,000
Asset retirement obligation, current portion		40,200			56,400
Deferred income taxes, current		-			122,000

Total current liabilities		2,456,380			3,534,886

Long-term liabilities
Notes payable, net of current portion		66,667			116,667
Asset retirement obligation, net of current portion		605,800			675,955
Deferred income taxes		3,873,500			3,971,500

Total long-term liabilities		4,545,967			4,764,122

Stockholders' equity:

Common stock, $.005 par value:
Authorized: 50,000,000 shares
Issued and outstanding: At September 30, 2008,
and June 30, 2008, 7,259,622 shares		36,298			36,298
Capital in excess of par value		7,676,458			7,676,458
Accumulated other comprehensive loss		(545,775	)		(281,849	)
Retained earnings		4,385,879			4,270,889

Total stockholders' equity		11,552,860			11,701,796

Total liabilities and stockholders' equity	$	18,555,207		$	20,000,804

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

F-71

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended
	September 30,
	2008			2007

Revenues:
Oil and gas sales	$	1,293,117		$	1,220,822

Operating expenses:
Oil and gas production		404,692			264,916
Accretion, and depreciation, depletion and amortization		532,319			662,648
Selling, general and administrative		206,540			164,582

Total operating expenses		1,143,551			1,092,146

Income from operations		149,566			128,676

Other income (expenses)
Interest and other income		7,060			75,036
Interest and other (expenses)		(17,573	)		(18,335	)
Gain (loss) on investments		12,050			-

Total other income (expenses)		1,537			56,701

Income before income taxes		151,103			185,377
Provision for income taxes		(36,113	)		(35,771	)

Net income	$	114,990		$	149,606

Basic net income per share	$	0.02		$	0.02

Diluted net income per share	$	0.01		$	0.02

Weighted average number of common shares outstanding
used to calculate basic net income per share :		7,259,622			7,259,622
Effect of dilutive securities:
Equity based compensation		873,527			70,185
Weighted average number of common shares outstanding
used to calculate diluted net income per share :		8,133,149			7,329,807

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

F-72

Unaudited Condensed Statements of Other Comprehensive Income
Three Month Periods Ended September 30, 2008 and 2007

	Three Months Ended
	September 30,
	2008			2007

Net income	$	114,990		$	149,606
Unrealized losses on available-for-sale securities,
net of income tax of $174,005 and $112,635, respectively.		(261,025	)		(166,870	)

Other Comprehensive (loss)	$	(146,035	)	$	(17,264	)

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

F-73

ASPEN EXPLORATION CORPORATION AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended September 30,
	2008			2007

Cash Flows from Operating Activities:
Net income	$	114,990		$	149,606
Adjustments to reconcile net income to net cash provided by operating activities:
Accretion and depreciation, depletion, and amortization		532,319			662,648
Deferred income taxes		36,104			35,748
Compensation expense related to stock options granted		-			23,649
Realized (gain) on marketable securities		(12,050	)		-
Changes in assets and liabilities:
(Increase) decrease in current assets other than cash, cash equivalents, and short-term marketable securities		515,618			(455,293	)
Increase (decrease) in current liabilities other than notes payable and asset retirement obligation		(918,486	)		662,607

Net Cash Provided by Operating Activities		268,495			1,078,965

Cash Flows from Investing Activities:
Additions to oil and gas properties		(140,323	)		(1,623,949	)
Sales of securities		97,165			-
(Purchases) of securities		-			(300,000	)

Net Cash (Used in) Investing Activities		(43,158	)		(1,923,949	)

Cash Flows from Financing Activities:
Payment of long-term debt		(71,820	)		(62,500	)

Net Cash (Used in) Financing Activities		(71,820	)		(62,500	)

Net Increase (Decrease) in Cash and Cash Equivalents		153,517			(907,484	)

Cash and Cash Equivalents, beginning of year		1,595,150			4,057,279

Cash and Cash Equivalents, end of year	$	1,748,667		$	3,149,795

Supplemental disclosures of cash flow information:
Interest paid	$	17,573		$	18,335

Supplemental non-cash activity
Increase (decrease) in asset retirement obligation	$	(86,355	)	$	44,173

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

F-74

ASPEN EXPLORATION CORPORATION

Notes to Condensed Consolidated Financial Statements

(Unaudited)

September 30, 2008

NOTE 1 –BASIS OF PRESENTATION

The accompanying condensed consolidated financial statements of Aspen Exploration Corporation (the Company) are unaudited. However, in the opinion of management, the accompanying condensed consolidated financial statements reflect all adjustments, consisting of only normal recurring adjustments, necessary for fair presentation for the interim period.

The condensed consolidated financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in consolidated financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. Management believes the disclosures made are adequate to make the information not misleading and suggests that these condensed consolidated financial statements be read in conjunction with the consolidated financial statements and notes hereto included in the Company’s Form 10-KSB for the year ended June 30, 2008.

This Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this Form 10-Q, including, without limitation, the statements under both “Notes to Consolidated Financial Statements” and “Item 2. Management’s Discussion and Analysis” located elsewhere herein regarding the Company’s financial position and liquidity, its strategies, financial instruments, and other matters, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations are disclosed in this Form 10-Q in conjunction with the forward-looking statements.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Accounting principles generally accepted in the United States of America require certain estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent liabilities at the date of the financial statements and reported amounts of revenues and expenses to be made. Actual results could differ from those estimates. The Company’s significant estimates include the carrying value of our oil and gas property, estimated life of long-lived assets, use of reserves in the estimation of depletion of oil and gas properties, impairment of oil and gas properties, asset retirement obligation abilities, and income taxes.

Cash and Cash Equivalents

For purposes of the Consolidated Balance Sheets and Statements of Cash Flows, we consider all highly liquid investments with a maturity of ninety days or less when purchased to be cash equivalents.

Investments in Debt and Equity Securities

The Company classifies all investments as available for sale securities in accordance with Financial Accounting Standards Board Statement of Financial Accounting Standards (SFAS) No. 115, Accounting for Certain Investments in Debt and Equity Securities . Changes in the fair value of the securities are reported as a separate component of shareholders’ equity until realized.

F-75

NOTE 2 –SIGNIFICANT ACCOUNTING POLICIES(Continued)

Oil and Gas Property

Aspen utilizes the full cost method of accounting for costs related to its oil and gas property. Capitalized costs included in the full cost pool are depleted on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence and results in lower depreciation and depletion in future periods. The write-down may not be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling.

Oil and Gas Reserves

The determination of depreciation and depletion expense as well as ceiling test write-downs, if any, related to the recorded value of Aspen’s oil and gas properties are highly dependent on the estimates of the proved oil and gas reserves attributable to these properties. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates are often different from the quantities of oil and gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. Aspen’s oil and gas reserves are based on estimates prepared by an independent petroleum engineering firm.

Asset Retirement Obligations

Aspen hsa obligations related to the plugging and abandonment of our oil and gas wells, the removal of equipment and facilities, and returning the land to its original condition. SFAS No. 143, “Accounting for Asset Retirement Obligations” requires that we estimate the future cost of this obligation, discount this cost to its present value, and record a corresponding asset and liability in our Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash expenditures, and inflation rates. The nature of these estimates requires Aspen to make judgments based on historical experience and future expectations related to timing. Aspen reviews the estimate of its future asset retirement obligations quarterly. These quarterly reviews may require revisions to these estimates based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis. Revisions for the quarter ending September 30, 2008 resulted in a decrease in asset retirement obligations and the related asset of approximately $98,000.

Aspen recognizes two components on its consolidated statement of operations; accretion of asset retirement obligations and asset retirement expense. Accretion of asset retirement obligation reflects the periodic accretion of the present value of future plugging and abandonment costs. Asset retirement expense reflects the actual current period gains and losses on plugging and abandonment costs relative to previously estimated future costs.

F-76

NOTE 2 –SIGNIFICANT ACCOUNTING POLICIES(Continued)

Income Taxes

Aspen accounts for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”. Accordingly, deferred tax assets and liabilities are determined based on the temporary differences between the financial statements and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse.

Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, the net deferred tax liability is continually re-evaluated and numerous estimates are revised over time. As such, the net deferred tax liability may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of oil and gas reserves, and the depletion of these long-lived reserves.

Earnings Per Share

Aspen’s earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share is calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options.

Equity Compensation Plans

At September 30, 2008, the Company had three share-based employee compensation plans, which are described in the Notes to Consolidated Financial Statements in the Company’s Annual Report on Form 10-KSB for the year ended June 30, 2008. No compensation expense related to our equity compensation plans was recognized in the current quarter.

Off Balance Sheet Transactions, Arrangements, or Obligations

Aspen has no material off balance sheet transactions, arrangements or obligations.

Recent Accounting Pronouncements

In September 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Positions (FSP) No. 133-1 and FIN 45-4 to amend SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a hybrid instrument. This FSP also amends FASB Interpretation No.45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to require an additional disclosure about the current status of the payment/performance risk of a guarantee. Further, this FSP clarifies the FASB’s intent about the effective date of FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities . Aspen does not expect the adoption of this FSP to have a material effect on our financial statements and related disclosures. This FSP is effective for financial statements issued for reporting periods (annual or interim) ending after November 15, 2008, with early application encouraged.

F-77

NOTE 3 –ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss for the periods ending September 30, 2008 and 2007 consists of unrealized losses on available-for-sale securities. Changes in accumulated other comprehensive loss for the quarters ended September 30, 2008 and 2007 are as follows:

	2008			2007

Accumulated other comprehensive loss, July 1	$	(281,849	)	$	-
Unrealized losses on available-for-sale securities, net		(261,025	)		(166,870	)
Less: reclassification adjustment for gains realized in net income		(2,901	)		-

Accumulated other comprehensive loss, September 30	$	(545,775	)	$	(166,870	)

NOTE 4 –FAIR VALUE MEASUREMENTS

In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurements” in order to establish a single definition of fair value and a framework for measuring fair value in generally accepted accounting principles (GAAP) that is intended to result in increased consistency and comparability in fair value measurements. SFAS No. 157 also expands disclosures about fair value measurements. SFAS No. 157 applies whenever other authoritative literature requires (or permits) certain assets or liabilities to be measured at fair value, but does not expand the use of fair value. SFAS No. 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years with early adoption permitted.

In early 2008, the FASB issued Staff Position (FSP) FAS-157-2, “Effective Date of FASB Statement No. 157,” which delays by one year, the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The delay pertains to items including, but not limited to, non-financial assets and non-financial liabilities initially measured at fair value in a business combination, non-financial assets recorded at fair value at the time of donation, and long-lived assets measured at fair value for impairment assessment under SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets”.

The Company has adopted the portion of SFAS No. 157 that has not been delayed by FSP FAS-157-2 as of the beginning of its 2009 fiscal year, and plans to adopt the balance of its provisions as of the beginning of its 2010 fiscal year. Items carried at fair value on a recurring basis (to which SFAS No. 157 applies in fiscal 2009) consist of available for sale securities based on quoted prices in active or brokered markets for identical as well as similar assets and liabilities. Items carried at fair value on a non-recurring basis (to which SFAS No. 157 will apply in fiscal 2010) generally consist of assets held for sale. The Company also uses fair value concepts to test various long-lived assets for impairment. The Company is continuing to evaluate the impact the standard will have on the determination of fair value related to non-financial assets and non-financial liabilities in post-2009 years.

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NOTE 4 –FAIR VALUE MEASUREMENTS (Continued)

Fair values of assets and liabilities measured on a recurring basis at September 30, 2008 are as follows:

	Fair Value Measurements at Reporting Date Using
			Quoted Prices
			In Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
			Assets/Liabilities		Inputs		Inputs
	Fair Value		(Level 1)		(Level 2)		(Level 3)

Available-for-sale securities	$	410,673	$	410,673	$	-	$	-

Notes payable	$	519,847	$	-	$	519,847	$	-

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PART II - INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20. Indemnification of Directors and Officers

Pursuant to Section 317 of the California Corporations Code, Royale is empowered to indemnify any person who was or is a party or is threatened to be made a party to any proceeding (other than an action by or in the right of the corporation to procure a judgment in its favor) by reason of the fact that such person is or was an officer, director, employee or other agent of Royale or its subsidiaries, against expenses, judgments, fines, settlements, and other amounts actually and reasonably incurred in connection with such proceeding, if such person acted in good faith and in a manner such person reasonably believed to be in the best interests of the corporation and, in the case of a criminal proceeding, had no reasonable cause to believe the conduct of such person was unlawful. In addition, Royale may indemnify, subject to certain exceptions, any person who was or is a party or is threatened to be made a party to any threatened, pending, or completed action by or in the right of Royale to procure a judgment in its favor by reason of the fact that such person is or was an officer, director, employee or other agent of Royale or its subsidiaries, against expenses actually and reasonably incurred by such person in connection with the defense or settlement of such action if such person acted in good faith, in a manner such person believed to be including reasonably inquiry, as an ordinarily prudent person in a like position would use under similar circumstances, provided that court approval is obtained in the case of an adverse judgment or settlement. Royale is required to advance expenses incurred by an officer or director in defending any proceeding prior to final disposition upon receipt of an undertaking to repay, unless it shall be determined ultimately that the officer or director is entitled to indemnification.

Article IV of Royale's Articles of Incorporation requires Royale to indemnify its officers and directors to the maximum extent permitted by California law and authorizes Royale to indemnify its officers and directors in excess of the provisions of Section 317 of the California Corporations Code.

Royale has entered into indemnification agreements with each of Royale's directors and with Donald H. Hosmer and Stephen M. Hosmer as officers of Royale. In general, the indemnification agreements provide that Royale shall indemnify such officer or director from any and all expenses in any proceeding or threatened proceeding by reason of an indemnification event. The term indemnification event shall mean any event or occurrence related to the fact that such officer or director is an officer or director of Royale or anything done or not done by such officer or director while serving as such. Expenses shall mean all expenses, including without limitation, attorneys' fees, fines, judgments, interest or other amounts paid in settlement. In addition, the agreement requires Royale to advance such expenses to such officer or director if so requested.

Item 21. Exhibits and Financial Statements

See the Exhibit Index which is incorporated herein by reference.

Item 22. Undertakings

The undersigned registrant hereby undertakes:

(a) to file, during any period in which it offers or sells securities, a post-effective amendment to this registration statement:

(1) to include any prospectus required by section 10(a)(3) of the Securities Act of 1933.

(2) to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set for the in the "Calculation of Registration Fee" table in the effective registration statement.

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(3) to include any additional material information on the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

provided, however, that paragraphs (a)(1), (a)(2) and (a)(3) do not apply if the information required to be included in a post-effective amendment by those paragraphs is contained in periodic reports filed with or furnished to the Securities and Exchange Commission by Royale pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the Registration Statement, or is contained in a form of prospectus filed pursuant to Rule 424(b) that is part of the Registration Statement.

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser:

(i) If the registrant is relying on Rule 430B:

(A) Each prospectus filed by the registrant pursuant to Rule 424(b)(3) shall be deemed to be part of the registration statement as of the date the filed prospectus was deemed part of and included in the registration statement; and

(B) Each prospectus required to be filed pursuant to Rule 424(b)(2), (b)(5), or (b)(7) as part of a registration statement in reliance on Rule 430B relating to an offering made pursuant to Rule 415(a)(1)(i), (vii), or (x) for the purpose of providing the information required by section 10(a) of the Securities Act of 1933 shall be deemed to be part of and included in the registration statement as of the earlier of the date such form of prospectus is first used after effectiveness or the date of the first contract of sale of securities in the offering described in the prospectus. As provided in Rule 430B, for liability purposes of the issuer and any person that is at that date an underwriter, such date shall be deemed to be a new effective date of the registration statement relating to the securities in the registration statement to which that prospectus relates, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such effective date, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such effective date; or prospectus relates, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such effective date, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such effective date; or

(ii)

If the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

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(b) that, for the purpose of determining any liability under the Securities Act of 1933, Royale will treat each post-effective amendment as a new registration statement relating to the securities offered therein, and the offering of the securities at that time to be the initial bona fide offering thereof.

(c) to remove from registration by means of a post-effective amendment any of the securities that remain unsold at the termination of the offering.

(d) for the purposes of determining any liability under the Securities Act of 1933, each filing of Royale's annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 shall be deemed to be a new registration statement relating to the securities offered herein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(e) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers, and controlling persons of Royale pursuant to the foregoing provisions of this registration statement, or otherwise, Royale has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by Royale of expenses incurred or paid by a director, officer or controlling person of Royale in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, Royale will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

Additionally, the undersigned registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11 or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

Additionally, the undersigned registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Donald H. Hosmer or Stephen M. Hosmer, or either of them, as his true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement, and to file the same with all exhibits thereto, and all documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, Royale, Inc., certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized in the City of San Diego, State of California, on November 25, 2008.

	Royale Energy, Inc.

	/s/ Donald H. Hosmer
	Donald H. Hosmer
	Co-President and Co-Chief Executive Officer

	/s/ Stephen M. Hosmer
	Stephen M. Hosmer
	Co-President and Co-Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons, in the capacities and on the dates indicated.

Date: November 25, 2008	/s/ Harry E. Hosmer
	Harry E. Hosmer, Chairman of the Board

Date: November 25, 2008	/s/ Donald H. Hosmer
	Donald H. Hosmer, Co-President, Co-Chief Executive Officer, Secretary, and Director (Co-Principal Executive Officer)

Date: November 25, 2008	/s/ Stephen M. Hosmer
	Stephen M. Hosmer, Co-President, Co-Chief Executive Officer, Chief Financial Officer and Director (Co-Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer)

Date: November 25, 2008	/s/ Gary Grinsfelder
	Gary Grinsfelder, Director

Date: November 25, 2008	/s/ Tony Hall
	Tony Hall, Director

Date: November 25, 2008	/s/ Oscar A. Hildebrandt
	Oscar A. Hildebrandt, Director

Date: November 25, 2008	/s/ Gilbert C. L. Kemp
	Gilbert C. L. Kemp, Director

Date: November 25, 2008	/s/ George M. Watters
	George M. Watters, Director

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EXHIBIT INDEX

Exhibit	Description

3.1	Amended and Restated Articles of Incorporation of Royale Energy, Inc., incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-3 filed July 10, 2008.

3.3	Bylaws of Royale Energy, Inc., incorporated by reference to Exhibit 3.2 of the Company's Form 10-SB Registration Statement.

4.1	Warrant issued to Cranshire Capital, L.P., incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K dated June 10, 2008.

4.2	Warrant issued to J.P. Turner Partners, L.P., incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-3 filed July 10, 2008.

4.3	Certificate of Determination of the Series AA Convertible Preferred Stock, incorporated by reference to Exhibit 4.2 of the Company's 10-SB Registration Statement.

5.1+	Opinion of Strasburger & Price, L.L.P., as to the validity of the shares being offered.

10.1	Securities Purchase Agreement between the Company and Cranshire Capital, L.P., dated as of June 7, 2008, incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K dated June 10, 2008.

10.2	Registration Rights Agreement between the Company and Cranshire Capital, L.P., dated as of June 7, 2008, incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K dated June 10, 2008.

10.3	Financial Representative Agreement between the Company and J.P. Turner & Company, LLC, dated May 28, 2008, incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-3 filed July 10, 2008..

23.1*	Consent of Padgett, Stratemann & Co., LLP.

23.2+	Consent of Strasburger & Price, L.L.P.

23.3*	Consent of Netherland, Sewell & Associates, Inc.

24.1*	Power of Attorney, included on signature page.

* Filed with this Form S-4.

+ To be filed by Amendment.

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