Royale Energy Funds 10-K 2006 FY Annual report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2006 Commission File No. 0-22750

ROYALE ENERGY, INC.

(Name of registrant in its charter)

California	33-0224120
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

7676 Hazard Center Drive, Suite 1500

San Diego, CA 92108

(Address of principal executive offices)

Issuer's telephone number:619-881-2800

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

None

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

Common Stock, par value $.01 per share

Indicate by check mark if the registrant is a well known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  [  ]; No [X]

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

Yes [  ]; No [X]

Check whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] ; No [  ]

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained herein, and will not be contained, to the best or registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.

Large accelerated filer _____          Accelerated filer _____          Non-accelerated filer [X]

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

Yes [  ]; No [X]

At June 30, 2006, the end of the registrant's most recently completed second fiscal quarter, the aggregate market value of common equity held by non-affiliates was $24,925,030.

At December 31, 2006, 7,916,408 shares of registrant's Common Stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: The issuer's proxy statement for its annual meeting of stockholders, to be filed within 120 days after December 31, 2006, will contain the information required by Part III, Items 10, 11, 12, 13 and 14, which information is hereby incorporated by reference into this Form 10-K.

Table of Contents
PART I			1
	Item 1	Description of Business	1
		Plan of Business	2
		Competition, Markets and Regulation	4
	Item 1A	Risk Factors	5
	Item 2	Description of Property	10
		Northern California	11
		Developed and Undeveloped Leasehold Acreage	11
		Drilling Activities	11
		Production	12
		Net Proved Oil and Natural Gas Reserves	13
	Item 3	Legal Proceedings	13
	Item 4	Submission of Matters to a Vote of Security Holders	13
PART II			14
	Item 5	Market for Common Equity and Related Stockholder Matters	14
		Dividends	14
		Recent Sales of Unregistered Securities	14
	Item 6	Selected Financial Data	15
	Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	16
		Critical Accounting Policies	17
		Changes in Accounting Principles	18
		Results of Operations for the Twelve Months Ended December 31, 2006, as Compared to the Twelve Months Ended December 31, 2005	18
		Results of Operations for the Twelve Months Ended December 31, 2005, as Compared to the Twelve Months Ended December 31, 2004	21
		Capital Resources and Liquidity	24
		Changes in Reserve Estimates	26
	Item 7A	Qualitative and Quantitative Disclosures about Market Risk	27
	Item 8	Financial Statements	28
	Item 9A	Controls and Procedures	28
PART III			28
	Item 10	Directors and Executive Officers of the Registrant	28
	Item 11	Executive Compensation	28
	Item 12	Security Ownership of Certain Beneficial Owners and Management	29
	Item 13	Certain Relationships and Related Transactions	29
	Item 14	Principal Accountant Fees and Services	29
	Item 15	Exhibits and Financial Statement Schedules	29
	Signatures		31
	Financial Statements		32

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ROYALE ENERGY, INC.

PART I

Item 1            Description of Business

Royale Energy, Inc. ("Royale Energy") is an independent oil and natural gas producer. Royale Energy'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 National Market System (symbol ROYL). On December 31, 2006, Royale Energy had 30 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 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, 2006, Royale Energy continued to explore and develop natural gas properties in northern California. We also own proved developed producing reserves of oil and natural gas in Texas and Louisiana. Royale Energy drilled 16 wells in 2006, ten of which are currently commercially productive wells. Royale Energy's estimated total reserves decreased from approximately 11.4 Bcfe (billion cubic feet equivalent) at December 31, 2005 to approximately 8.5 Bcfe at December 31, 2006. According to the reserve report furnished to Royale Energy by WZI, Inc., Royale Energy's independent petroleum engineers, the net present value of its proved developed and undeveloped reserves was more than $33.5 million at December 31, 2006, based on natural gas prices ranging from $5.25 per Mcf to $8.66 per Mcf. Of course, net present 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 presen t 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, 2006, was estimated to be $16,646,551. This figure was calculated by subtracting our estimated future income, tax expense from the net present 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

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Supplemental Information About Oil and Gas Producing Activities - Changes in Standardized Measure of Discounted Future Net Cash Flow from Proved Reserve Quantities, page F-32.

Royale Energy 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 $15,711,550 for the year ended December 31, 2006, which represents 63% of its total revenues for the year. In 2005, Royale Energy reported $13,066,800 gross revenues from turnkey drilling operations for the year, representing 51% of Royale Energy's total revenues for that year.

These amounts are offset by drilling expenses and development costs of $9,628,394 in 2006, and $8,111,248 in 2005. In addition to Royale Energy's own geological, land, and engineering staff, Royale Energy hires independent contractors to drill, test, complete and equip the wells that it drills.

Approximately 32% of Royale Energy's total revenue for the year ended December 31, 2006 came from sales of oil and natural gas from production of its wells in the amount of $7,965,633. In 2005, this amount was $11,228,537, which represented 43.8% of Royale Energy's total revenues.

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. In addition to the net book values of the 19 wells and facilities, the net book value of 11 non-producing wells was included in the total cost of sales. These 11 wells were written down because their net book values were no longer supported by the reserves of the sold wells. See Management Discussion and Analysis - Results of Operations 2005-2006.

Plan of Business

Royale Energy acquires interests in oil and natural gas reserves and sponsors private joint ventures. Royale Energy believes that its stockholders are better served by diversification of its investments among individual drilling prospects. Through its sale of joint ventures, Royale Energy 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 Energy 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 Energy drills or participates in the drilling of development and exploratory oil and natural gas wells on its property. Royale Energy 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 Energy 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 Energy sells

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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 Energy 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 Energy received from the fractional interest sale.

When Royale Energy 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 Energy. 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 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.See Note 1 to Royale Energy's Financial Statements, at page F-11. Royale Energy maintains internal records of the expenditure of each investor's funds for drilling projects.

Royale Energy 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, 2006, Royale Energy earned gross revenues from operation of the wells in the amount of $484,615, representing 1.9% of its total revenues on a consolidated basis for that year. In 2005, the amount was $493,415, which represented about 1.9% of total revenues. At December 31, 2006, Royale Energy operated 48 natural gas wells in California. Royale also owns an interest and operates two natural gas wells in Utah and has non-operating interests in 20 oil and gas wells in Texas, three in Oklahoma, two in California, and two in Louisiana.

Royale Energy 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 Energy'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.

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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 Energy had no subsidiaries in 2006.

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 Energy sells, is also very competitive. Royale Energy 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 Energy.

Markets

Market factors affect the quantities of oil and natural gas production and the price Royale Energy 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 Energy's operations. States in which Royale Energy 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

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legislation and regulations, together with any penalties resulting from failing to comply with the legislation and regulations. Ultimately, Royale Energy may bear some of these costs.

Presently, Royale Energy 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 Energy's financial condition or results of operation.

Royale Energy files quarterly, yearly and other reports with the Securities Exchange Commission. You may obtain a copy of any materials filed by Royale Energy with the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549 or by calling 1-800-SEC-0300. The SEC also maintains an Internet site that contains reports, proxy and information statements, and other

information regarding issuers that file electronically with the SEC at http://www.sec.gov. Royale Energy also provides access to its SEC reports and other public announcements on its website, http://www.royl.com.

Item 1A          Risk Factors

In addition to the other information contained in this report, the following risk factors should be considered in evaluating our business.

We Depend on Market Conditions and Prices in the Oil and Gas Industry.

Our success depends heavily upon our ability to market oil and gas production at favorable prices. In recent decades, there have been both periods of worldwide overproduction and underproduction of hydrocarbons and periods of increased and relaxed energy conservation efforts. As a result the world has experienced periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis; these periods have been followed by periods of short supply of, and increased demand for, crude oil and, to a lesser extent, natural gas. The excess or short supply of oil and gas has placed pressures on prices and has resulted in dramatic price fluctuations.

Natural gas demand and the prices paid for gas are seasonal. The fluctuations in gas prices and possible new regulations create uncertainty about whether we can continue to produce gas for a profit.

Prices for oil and natural gas affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. Any substantial and extended decline in the price of oil or natural gas would decrease our cash flows, as well as the carrying value of our proved reserves, our borrowing capacity and our ability to obtain additional capital.

Variance in Estimates of Oil and Gas Reserves could be Material.

The process of estimating oil and gas reserves is complex, requiring significant decisions and

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assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, such estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated in reserve reports that we periodically obtain from independent reserve engineers.

You should not construe the standardized measure of proved reserves contained in our annual report as the current market value of the estimated proved reserves of oil and gas attributable to our properties. In accordance with Securities and Exchange Commission requirements, we have based the standardized measure of future net cash flows from the standardized measure of proved reserves on prices and costs as of the date of the estimate, whereas actual future prices and costs may vary significantly. The following factors may also affect actual future net cash flows:

- the timing of both production and related expenses;

- changes in consumption levels; and

- governmental regulations or taxation.

In addition, the calculation of the standardized measure of the future net cash flows using a 10% discount as required by the Securities and Exchange Commission is not necessarily the most appropriate discount rate based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas industry in general. Furthermore, we may need to revise our reserves downward or upward based upon actual production, results of future development, supply and demand for oil and gas, prevailing oil and gas prices and other factors.

Any significant variance in these assumptions could materially affect the estimated quantities and present value of our reserves. In addition, our standardized measure of proved reserves may be revised downward or upward, based upon production history, results of future exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used, and such variances may be material.

Future Acquisitions and Development Activities May Not Result in Additional Proved Reserves, and We May Not be Able to Drill Productive Wells at Acceptable Costs.

In general, the volume of production from oil and gas properties declines as reserves are depleted. Except to the extent that we acquire properties containing proved reserves or conduct successful development and exploitation activities, or both, our proved reserves will decline as reserves are produced. Our future oil and gas production is, therefore, highly dependent upon our ability to find or acquire additional reserves.

The business of acquiring, enhancing or developing reserves is capital intensive. We require cash flow from operations as well as outside investments to fund our acquisition and development activities. If our cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be impaired.

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Increased Activity and Competition for Drilling Rigs and Equipment May Impair Our Ability to Acquire New Reserves.

In 2005 and 2006, drilling activity continued to increase in the areas where we operate. The increased activity made it more difficult for us to obtain drilling rigs, equipment and services in a

timely manner and slowed our drilling and development program. These delays have contributed to a decline in our gas reserves as we have been unable to replace normal production declines with production from new wells. Continued delays in drilling could cause further declines in our gas production, reserves and revenues.

The Oil and Gas Industry has Mechanical and Environmental Risks.

Oil and gas drilling and production activities are subject to numerous risks. These risks include

the risk that no commercially productive oil or gas reservoirs will be encountered, that operations may be curtailed, delayed or canceled, and that title problems, weather conditions, compliance with governmental requirements, mechanical difficulties or shortages or delays in the delivery of drilling rigs and other equipment may limit our ability to develop, produce or market our reserves. New wells we drill may not be productive and we may not recover all or any portion of our investment in the well. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. In addition, our properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties.

Industry operating risks include the risks of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards, such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with customary industry practice, we maintain insurance for these kinds of risks, but we cannot be sure that our level of insurance will cover all losses in the event of a drilling or production catastrophe. Insurance is not available for all operational risks, such as risks that we will drill a dry hole, fail in an attempt to complete a well or have problems maintaining production from existing wells.

Drilling is a Speculative Activity Even With Newer Technology.

Assessing drilling prospects is uncertain and risky for many reasons. We have grown in the past several years by using 3-D seismic technology to acquire and develop exploratory projects in northern California, as well as by acquiring producing properties for further development. The successful acquisition of such properties depends on our ability to assess recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities and other factors.

Nevertheless, exploratory drilling remains a speculative activity. Even when fully utilized and properly interpreted, 3-D seismic data and other advanced technologies assist geoscientists in

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identifying subsurface structures but do not enable the interpreter to know whether hydrocarbons are in fact present. In addition, 3-D seismic and other advanced technologies require greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of these costs.

Therefore, our assessments of drilling prospects are necessarily inexact and their accuracy inherently uncertain. In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Such a review, however, will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.

Breaches of Contract by Sellers of Properties Could Adversely Affect Operations.

In most cases, we are not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and we generally acquire interests in the properties on an "as is" basis with limited remedies for breaches of representations and warranties. In those circumstances in which we have contractual indemnification rights for pre-closing liabilities, the seller may not fulfill those obligations and leave us with the costs.

We May Not be Able to Acquire Producing Oil and Gas Properties Which Contain Economically Recoverable Reserves.

Competition for producing oil and gas properties is intense and many of our competitors have substantially greater financial and other resources than we do. Acquisitions of producing oil and gas properties may be at prices that are too high to be acceptable.

We Require Substantial Capital for Exploration and Development.

We make substantial capital expenditures for our exploration and development projects. We will finance these capital expenditures with cash flow from operations and sales of direct working interests to third party investors. We will need additional financing in the future to fund our developmental and exploration activities. Additional financing that may be required may not be available or continue to be available to us. If additional capital resources are not available to us, our developmental and other activities may be curtailed, which would harm our business, financial condition and results of operations.

Profit Depends on the Marketability of Production.

The marketability of our natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Most of our natural gas is delivered through natural gas gathering systems and natural gas pipelines that we do not own. Federal, state and local regulation of oil and gas production and transportation, tax and energy policies, and/or changes in supply and demand and general economic conditions could adversely affect our ability to produce and market its oil and gas. Any dramatic change in market factors could have a material adverse effect on our financial condition and results in operations.

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We Depend on Key Personnel.

Our business will depend on the continued services of our president and chief executive officer, Donald H. Hosmer, and executive vice president and chief financial officer, Stephen M. Hosmer. We do not have employment agreements with either Donald or Stephen Hosmer. The loss of the services of either of these individuals would be particularly detrimental to us because of their background and experience in the oil and gas industry.

The Hosmer Family Exerts Significant Influence Over Stockholder Matters.

The control positions held by members of the Hosmer family may discourage others from making bids to buy Royale Energy or change its management without their consent. Donald H. Hosmer is the president of the company. Stephen M. Hosmer is executive vice president and chief financial officer. Harry E. Hosmer is the chairman of the board. Together, they make up three of the seven members of our board of directors. At December 31, 2006, these individuals owned or controlled the following amounts of Royale Energy 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	990,437	12.51%
Stephen M. Hosmer	1,164,840	14.71%
Harry E. Hosmer	763,797	9.65%
Total	2,919,074	36.87%

                 * Based on total of 7,916,408 outstanding shares on December 31, 2006.

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 ofproducing 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.

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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 r egulatory 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.

Item 2          Description of Property

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 2006, Royale Energy drilled eleven wells in northern and central California, six of which were commercially productive wells and are currently producing. Additionally, Royale participated in drilling five wells in Texas, four of which were commercially productive and are currently producing.

Following industry standards, Royale Energy generally acquires oil and natural gas acreage

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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, 2006, was $3,820,974. At December 31, 2006, Royale Energy owed $3,810,000 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, 2006, for each property discussed below, have been determined by WZI, Inc., registered professional petroleum engineers, in accordance with its report submitted to Royale Energy on March 12, 2007.

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, 2006, Royale operated 48 wells in California with estimated total proven, developed, and undeveloped reserves at approximately 5.2 bcf, according to Royale's independently prepared reserve report as of December 31, 2006.

Developed and Undeveloped Leasehold Acreage

As of December 31, 2006, Royale Energy owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.

	Developed		Undeveloped
	Gross Acres	Net Acres	Gross Acres	Net Acres
California	13,975.25	8,445.01	6,944.41	6,371.51
All Other States	11,986.21	4,054.06	29,511.93	15,328.30
Total	25,961.46	12,499.07	36,456.34	21,699.81

Drilling Activities

The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2004, 2005 and 2006. All wells are located in the Continental U.S., in California, Texas, Louisiana and Utah.

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	Type of Well(a)		Gross Wells(b)		Net Wells(c)
		Total	Producing(c)	Dry(d)	Producing(c)	Dry(d)
2004	Exploratory	10	6	4	1.6408	1.9175
	Developmental	4	3	1	.8390	0.0371
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

(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.

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	2006	2005	2004
Net volume
Oil (Bbl)	21,325	16,558	20,017
Gas (Mcf)	1,074,573	1,384,860	1,870,250
Mcfe	1,287,823	1,550,440	2,070,420
Average sales price
Oil (Bbl)	$60.34	$       51.95	$        36.66
Gas (Mcf)	$6.21	$         7.48	$          5.43
Net production costs and taxes	$1,968,269	$2,751,441	$2,817,448
Lifting costs (per Mcfe)	$1.53	$         1.77	$         1.36

Net Proved Oil and Natural Gas Reserves

As of December 31, 2006, Royale Energy had proved developed reserves of 4,129 MMcf and total proved reserves of 8,160 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 37 Mbbl and total proved oil reserves of 37 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.

Item 3          Legal Proceedings

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 an interest in the drilling of one other well. The lawsuit also includes disputes over the manner in which Royale charges for operation of wells,. The company denies the allegation and believes it will prevail at trial.

Item 4          Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during the fourth quarter of 2006.

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PART II

Item 5          Market For Common Equity and Related Stockholder Matters

Since 1997 Royale Energy's Common Stock has been traded on the Nasdaq National Market System under the symbol "ROYL." As of December 31, 2006, 7,916,408 shares of Royale Energy's Common Stock were held by approximately 3,099 stockholders. The following table reflects high and low quarterly closing sales prices from January 2004 through December 2006. 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.

	1st Qtr		2nd Qtr		3rd Qtr		4th Qtr
	High	Low	High	Low	High	Low	High	Low
2006	7.23	5.55	6.93	4.95	5.66	3.86	4.92	3.50
2005	9.39	7.00	11.69	4.83	10.20	7.31	10.28	6.35

Dividends

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

In June 2005, Royale Energy awarded shares of restricted common stock to certain of its employees pursuant to an incentive compensation plan. A total of 4,612 and 6,048 shares of vested restricted common stock were issued in 2006 and 2005, respectively. An additional 7,490 shares of unvested stock were awarded with vesting dates in 2007. 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 2006.

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, 2000, with the cumulative total return of the Standard & Poor's Composite 500 Stock Index and the Dow Jones U.S. Exploration and Production Index (formerly Dow Jones Secondary Oils Stock Index) from December 31, 2001 through December 31, 2006. The Royale Energy performance figures

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assume retention of stock dividends in 2001, 2002, 2003 and 2004 and a stock split issued in the form of a stock dividend in 2004.

	2001	2002	2003	2004	2005	2006
Royale Energy, Inc.	100	92	248	195	172	93
S & P Composite 500 Stock Index	100	78	100	111	117	135
DJ US Exploration and Production Index	100	102	134	188	314	331

Item 6          Selected Financial Data

	(In thousands, except earnings per share data) As of December 31,
	2006	2004	2003	2002
Income Statement Data:
Revenues	$ 24,896	$ 25,643	$ 23,265	$ 12,440
Operating Income (Loss)	(3,189)	2,257	6,854	(87)
Net Income (Loss)	(2,650)	1,186	4,401	(137)
Basic Earnings Per Share	(0.33)	0.15	0.72	(0.02)
Balance Sheet Data:
Oil & Gas Properties,     Equipment & Fixtures	$ 20,526	$ 31,221	$ 22,904	$ 15,177
Total Assets	33,715	43,043	35,671	23,301
Long Term Obligations	5,757	10,768	7,614	3,500
Total Stockholders' Equity	15,548	18,318	15,269	11,203

Item 7          Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with Royale Energy's Financial

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Statements and Notes thereto and other financial information relating to Royale Energy included elsewhere in this document.

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

Critical Accounting Policies

Revenue Recognition

Royale Energy's financial statements include itspro rata ownership of wells. 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. Royale Energy generally retains about a 50% working interest. All results, successful or not, are included at itspro rata ownership amounts: revenue, expenses, assets, and liabilities.

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

Royale Energy 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 Energy recognizes the pre-drilling revenue portion when the investor deposits money with Royale Energy. 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, 2006 and 2005, Royale Energy had deferred drilling revenue of $5,018,261 and $6,490,111, respectively.

The second business segment is oil and gas production. Northern and central California account for approximately 85% 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 Energy and other working interest owners. Royale Energy operates virtually all of its own wells and receives industry standard operator fees.

Oil and Gas Property and Equipment

Royale Energy 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

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are excluded from amortization until the properties are evaluated. Royale Energy 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 Energy 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 rese rves 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 o r based on fair market values. We regard impairment costs 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

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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.

Changes in Accounting Principles

Asset Retirement Obligations

In June 2001, the FASB approved for issuance SFAS 143, "Asset Retirement Obligations." SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets such as wells and production facilities.See Note 4 to our Financial Statements -Summary of Significant Accounting Policies - Recently Issued Accounting Pronouncements. Royale Energy adopted the statement as of January 1, 2003.

Suspended Well Costs

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 performed an evaluation of our capitalized costs and determined that no previously capitalized exploratory well costs pending the determination of proved reserves were required to be expensed or reclassified during the third quarter of 2005 or 2004. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2006 or 2005. We did not charge any previously capitalized exploratory well costs to expense upon adoption of FSP FAS 19-1. At December 31, 2006 and 20 05, no capitalized well costs had been capitalized for more than one year.

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.

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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 a t 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 associa ted 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

19

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 to 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

20

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 ofapproximately 34.6%, respectively. The use of percentage depletion created from the current operations, and from utilization of unused percentagedepletion 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, 2005, as Compared to the Twelve Months Ended December 31, 2004

For the year ended December 31, 2005, we had a net profit of $1,185,903, a $1,006,849 or 45.9% decrease compared to the net profit of $2,192,752 achieved during 2004. We attribute this to higher lease impairment costs and intensifying marketing efforts. Total revenues for the year in 2005 were $25,643,378, a decrease of $300,978 or 1.2% from the total revenues of $25,944,356 in 2004. This was mainly due to lower cost recovery fees due to decreased production.

In 2005, revenues from oil and gas production increased by 3.1% to $11,228,537 from $10,892,574, due to increased natural gas and oil prices. The net sales volume of natural gas for the year ended December 31, 2005, was approximately 1,384,860 Mcf with an average price of $7.48 per Mcf, versus 1,870,250 Mcf with an average price of $5.43 per Mcf for 2004. This represents a decrease in net sales volume of 485,390 Mcf or 26%. This decrease in production

21

was a result of several factors including the natural decline on our oil and gas wells and the lack of new production because of a delay in starting our drilling projects due to limited drilling rig availability in California. The net sales volume for oil and condensate (natural gas liquids) production was 16,558 barrels with an average price of $51.95 per barrel for the year ended December 31, 2005, compared to 20,017 barrels at an average price of $36.66 per barrel for the year in 2004. This represents a decrease in net sales volume of 3,459 barrels, or 17.3%.

Oil and gas lease operating expenses decreased by $66,007, or 2.3%, to $2,751,441 for the year ended December 31, 2005, from $2,817,448 for the year in 2004. The decrease was due to a decrease in the number of operated wells. When measuring lease operating costs on a production or lifting cost basis, in 2005, the $2,751,441 equates to a $1.77 per Mcfe lifting cost versus a $1.36 per Mcfe lifting cost in 2004, a 30.1% increase.

For the year ended December 31, 2005, turnkey drilling revenues decreased $203,196 to $13,066,800 in 2005 from $13,269,996 in 2004, or 1.5%. We also had a $39,090 or 0.5% decrease in turnkey drilling and development costs to $8,111,248 in 2005 from $8,150,338 in 2004. The decrease in turnkey drilling revenues was mainly due to a decrease in direct working interest sales during the year in 2005 when compared to the year in 2004. The decrease in drilling and development costs was due to lower cost wells drilled in 2005 when compared to 2004. We drilled six exploratory wells and nine developmental in 2005 versus ten exploratory wells and four developmental wells in 2004. 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 37.9% and 38.6% for the years ended December 31, 2005 and 2004, 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 $742,642 and $51,414 were recorded in 2005 and 2004, respectively. In 2004, we determined that an impairment was appropriate in the Afton field, which was acquired in 2004, due to a delay in drilling exploratory wells in the field as a result of pipeline restrictions. In addition, we recorded an impairment for the Elkhorn Slough field due to cost overruns on our Kingfisher well due to mechanical problems while completing it.

During the second quarter of 2004, we suffered a blowout of our Bowerbank Sam #2 well during recompletion operations. The blowout and clean-up resulted in net costs of $386,807 chargeable to working interest investors for their share of the blowout. We created an allowance for theses expenses when they were incurred in 2004, while we decided whether to seek to recover them from Direct Working Interest investors. When the allowance was created, we also decided to have our internal accounting staff review other accounts receivable from investors for well expenses were doubtful and should be added to the allowance. Our internal review showed that working interest investor account balances in an amount of $641,872 (including the $386,807

22

attributed to the Bowerbank Sam #2) could not be collected from well operations alone, because those wells had ceased operating. These accounts were placed in the allowance as of year end. We ultimately decided not to seek recovery of theses costs from the working interest investors, and all of these receivables were written off in 2005.

The aggregate of supervisory fees and other income was $1,348,041 for the year ended December 31, 2005, a decrease of $433,745 (24.3%) from $1,781,786 during the year in 2004. This was due to a decrease in cost recovery received for use of facilities constructed and placed into service during prior periods due to lower production. 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 increased $6,009 or 1.2%, to $493,415 in 2005 from $487,406 in 2004.

Depreciation, depletion and amortization expense increased to $4,062,587 from $3,714,271, an increase of $348,316 (9.4%) for the year ended December 31, 2005, as compared to the same period in 2004. The depletion rate is calculated using production as a percentage of reserves. This increase in depletion expense was mainly due to an increase in the depletion rate because of higher rates of production when compared to total reserves and in the number of oil and gas assets that we own.

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, $381,790 of previously capitalized costs were written off and recorded as geological and geophysical expense during 2005 compared with $321,983 written off in 2004, a $59,807 or 18.6% increase.

General and administrative expenses decreased by $48,153 or 1.0%, from $4,925,321 for the year ended December 31, 2004 to $4,877,168 for the year in 2005. Legal and accounting expense decreased to $236,199 for the period, compared to $627,038 for year 2004, a $390,839 or 62.3% decrease. These decreases were due to lower audit, tax preparation and legal fees during the year in 2005. Marketing expense for the year ended December 31, 2005 increased $658,181, or 42.1%, to $2,222,859, compared to $1,564,678 for the year in 2004. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs. In 2005 we also increased the use of outside brokers to increase direct working interest sales.

During the period in 2005, we increased long-term debt under our commercial bank credit line. The interest rate charged to the company also increased from 6.0% at December 31, 2004, to 7.75% at December 31, 2005. This increased interest expense to $444,271 for the year ended December 31, 2005, from $273,050 for the same period in 2004, a $171,221, or 62.7% increase.

In 2005 our income tax expense decreased to $627,270 from $1,306,063 in 2004, a $678,793 or 52% decrease, mainly due to the decrease in our net income. For the periods in 2004 and 2005,

23

this represents an effective tax rate of approximately 37.3% and 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, 2006, Royale Energy had current assets totaling $13,182,297 and current liabilities totaling $12,409,918, a $772,379 working capital surplus. We had cash and cash equivalents at December 31, 2006 of $7,377,604 compared to $4,716,772 at December 31, 2005.

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. Webelieve 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 2006, our accounts receivable totaled $2,906,290 compared to $4,221,601 at December 31, 2005, a $1,315,311 or 31.2% decrease, mainly due to decreased revenue receivables due to lower natural gas prices at the end of 2006 as compared to 2005. At December 31, 2006, our accounts payable and accrued expenses totaled $7,158,612, a decrease of $216,549 or 2.9% over the accounts payable at the end of 2005 of $7,375,161. This was primarily due to payments on trade accounts payable from proceeds of the sale of oil and gas assets at the end of 2006.

Occasionally we borrow from banks, using our oil and gas properties as security. 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. During the year ended December 31, 2005, we drew approximately $972,500 net from our credit line in order to meet our drilling schedule.

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 December 31, 2006, we had outstanding

24

indebtedness of $3,810,000. Unused available credit from this revolving line of credit totaled approximately $10,974 at December 31, 2006. At December 31, 2005, we had outstanding indebtedness under this agreement of $6,400,000. 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.

At December 31, 2006, Royale Energy was in compliance with its loan covenants.

During 2004 we obtained a new loan from Guaranty Bank, FSB for $1,000,000, which is 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, 2006, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.

	Total Obligations	2007	2008-2009	2010-2011	Beyond
Office lease	$3,254,393	$338,520	$707,546	$750,020	$1,458,307
Long-term debt	4,043,045	233,045	3,810,000	-	-
Total	$7,297,438	$571,565	$4,517,546	$750,020	$1,458,307

Operating Activities.For the year ended December 31, 2006, cash provided by operating activities totaled $3,406,393 compared to $6,395,442 provided by operatingactivities for the same period in 2005, a $2,989,049 or 46.7% decrease, mainly due to our net loss from operations. Cash provided by operating activities for 2005 decreased $1,622,858 or 20.2% as compared to $8,018,300 for the year ended December 31, 2004 mainly due to decreases in net income from operations.

Investing Activities.Net cash provided by investing activities netted to $1,932,738 for the year in 2006, which included $3,091,316 used for oil and gas and other capital expenditures along with proceeds from our asset sales of $5,024,054, compared to $9,888,809 used by investing activities for the same period in 2005. Net cash used by investing activities in 2005 increased $3,248,706 compared to $6,640,103 used by investing activities for the same period in 2004.

25

This increase in cash used was primarily due to the increased number of wells drilled, nine developmental and six exploratory in 2005 and four developmental and 10 exploratory in 2004.

Financing Activities. For the year ended December 31, 2006 cash used by financing activities was $2,678,299 compared to $583,094 provided by financing activities for the same period in 2005. This difference in cash was primarily due to net principal loan repayments during 2006 when compared to 2005 due to the asset sale. The net cash provided by financing activities in 2005 of $583,094 decreased $788,136 when compared to $1,371,230 provided by financing activities for the same period in 2004. This difference in cash provided was primarily due to decreases in borrowings during 2005 when compared to 2004.

Changes in Reserve Estimates

In 2006, our estimated proved developed and undeveloped reserve quantities were revised downward by approximately 1.02 million cubic feet of natural gas 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), page F-30. During 2005, three producing wells ceased producing, resulting in a reduction in proved

26

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)

In 2004, the cessation of production from one well and significant downward revision of a second well accounted for downward revisions of more than 1.14 million cubic feet of proved developed reserves, which is 77% of the net revisions in 2004. Both wells had been producing gas wells. The reserve estimate for one well was revised downward by 622,928 cubic feet to 0, and the reserve estimate of the second well was revised downward by 521,714 cubic feet to 182,000 cubic feet.

Item 7A          Qualitative and Quantitative Disclosures About Market Risk

Royale Energy is exposed to market risk from changes in commodity prices and in interest rates. In 2006, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline. In 2006, our natural gas revenues were approximately $6.7 million with an average price of $6.21 per MCF. At current production levels, a 10% per MCF increase or decrease in our average price received could potentially increase or decrease our natural gas revenues by approximately $660,000. At our current production levels of oil and natural gas condensate, a 10% increase or decrease in our average price per barrel could potentially increase or decrease our oil and natural gas revenues by approximately $130,000. We currently do not sell any of our natural gas or oil through hedging contracts.

We have a line of credit used in funding purchases of oil and gas assets, meeting drilling schedules and assisting in funding operations. This line of credit is tied to increases or decreases in the bank prime interest rate. If the interest rate on our line of credit were to increase 1% or 2% during the year this could potentially add approximately $60,000 to $120,000, respectively, to our interest expense.

27

Item 8          Financial Statements

See pages F-1, et seq., included herein.

Item 9A        Controls and Procedures

Disclosure controls are controls and other procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Our disclosure controls and procedures are designed to insure that the information required to be filed is accumulated and communicated to our management in a manner designed to enable them to make timely decisions regarding required disclosure.

Our chief executive officer, Donald H. Hosmer, and chief financial officer, Stephen M. Hosmer, evaluated the effectiveness or our disclosure controls and procedures as of the end of the 2006 fiscal year. Based on their evaluation, they concluded that our disclosure controls are effective as of December 31, 2006.

No changes in our internal control over financial reporting occurred during the last fiscal quarter of 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our management, including our CEO and CFO, does not expect that our disclosure controls or internal controls over financial reporting will prevent all error or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, but not absolute, assurance that the objectives of a control system are met. Any control system contains limitations imposed by resources and relevant cost considerations. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues have teen addressed. These inherent limitations include the realities that judgments can be faulty and that breakdowns can occur because of simple error or mistake. In addition, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of a control. Our control system design is also based on assumptions about the likelihood of future events, and we cannot be sure that we hav e considered all possible future circumstances and events.

PART III

Item 10          Directors and Executive Officers of the Registrant

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will be filed with the SEC and mailed to stockholders within 120 days of December 31, 2006.

Item 11          Executive Compensation

The information required by this Item will be contained in, and incorporated by reference to, the

28

Proxy Statement for the annual meeting of Royale Energy, which will be filed with the SEC and mailed to stockholders within 120 days of December 31, 2006.

Item 12          Security Ownership of Certain Beneficial Owners and Management

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will be filed with the SEC and mailed to stockholders within 120 days of December 31, 2006.

Item 13          Certain Relationships and Related Transactions

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will be filed with the SEC and mailed to stockholders within 120 days of December 31, 2006.

Item 14          Principal Accountant Fees and Services

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will be filed with the SEC and mailed to stockholders within 120 days of December 31, 2006.

Item 15          Exhibits and Financial Statement Schedules

Financial Statements

1.       Financial Statements. See Index to Financial Statements, page F-1

2.       Schedules. Supplemental Information About Oil and Gas Producing Activities (Unaudited) begins on page F-30.

3.       Exhibits. Certain of the exhibits listed in the following index are incorporated by reference.

3.1	Restated Articles of Incorporation of Royale Energy, Inc., incorporated by reference to Exhibit 3.1 of Royale Energy's Form 10-SB Registration Statement.
3.2	Certificate of Amendment to the Articles of Incorporation of Royale Energy, Inc. (effecting reverse stock split and defining certain rights of equity security holders), incorporated by reference to Exhibit 3.1 of Royale Energy's Form 8-K dated October 31, 1994.
3.3	Bylaws of Royale Energy, Inc., incorporated by reference to Exhibit 3.2 of Royale Energy's Form 10-SB Registration Statement.

29

4.1	Certificate of Determination of the Series AA Convertible Preferred Stock, incorporated by reference to Exhibit 4.2 of Royale Energy's Form 10-SB Registration Statement.
10.1	Form of Indemnification Agreement, incorporated by reference to Exhibit 10.3 of Royale Energy's Form 10-SB Registration Statement.
31.1	Rules 13a-14(a), 115d-14(a) Certification, attached.
31.2	Rules 13a-14(a), 115d-14(a) Certification, attached.
32.1	Section 1350 Certification, attached.
32.2	Section 1350 Certification, attached.

30

Signatures

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

		Royale Energy, Inc.
Date:	April 13, 2007	/s/ Donald H. Hosmer
		Donald H. Hosmer, President and Chief Executive Officer

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

Date:	April 13, 2007	/s/ Harry E. Hosmer
		Harry E. Hosmer, Chairman of the Board of Directors
Date:	April 13, 2007	/s/ Donald H. Hosmer
		Donald H. Hosmer, Director, President, Chief Executive Officer and Secretary
Date:	April 13, 2007	/s/ Stephen M. Hosmer
		Stephen M. Hosmer, Director, Executive Vice President and Chief Financial Officer
Date:	April 13, 2007	/s/ Oscar A. Hildebrandt
		Oscar A. Hildebrandt, Director
Date:		_____________________
		Rodney Nahama, Director
Date:	April 13, 2007	/s/ Gilbert C.L. Kemp
		Gilbert C.L. Kemp, Director
Date:	April 13, 2007	/s/ George M. Watters
		George M. Watters, Director

31

ROYALE ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA

Index to Financial Statements	32
Report of Sprouse & Anderson, LLP, Independent Auditors	33
Balance Sheets at December 31, 2005 and 2004	34
Statements of Operations for the Years Ended December 31, 2005, 2004, and 2003	36
Statements of Stockholders' Equity for the Years Ended December 31, 2005, 2004, and 2003	37
Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003	40
Notes to the Financial Statements	42
Supplemental Information about Oil and Gas Producing Activities (Unaudited)	62

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.

32

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, 2006 and December 31, 2005, and the related statements of operations, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2006. 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 eva luating 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, 2006 and 2005, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

SPROUSE & ANDERSON, L.L.P.

Austin, Texas

April 6, 2007

33

ROYALE ENERGY, INC

BALANCE SHEETS

DECEMBER 31, 2006 AND 2005

ASSETS
	2006	2005
Current Assets
Cash and Cash Equivalents	$    7,377,604	$    4,716,772
Accounts Receivable, net	2,906,290	4,221,601
Prepaid Expenses	2,301,267	2,299,333
Deferred Tax Asset	195,615	194,468
Inventory	401,521	382,810
Total Current Assets	13,182,297	11,814,984
Investments	6,946	6,946
Oil And Gas Properties (Successful Efforts Basis)
Equipment and Fixtures	20,525,960	31,220,651
Total Assets	$   33,715,203	$  43,042,581

34

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

ROYALE ENERGY, INC.

BALANCE SHEETS

DECEMBER 31, 2006 AND 2005

LIABILITIES AND STOCKHOLDERS' EQUITY

	2006	2005
Current Liabilities:
Accounts Payable and Accrued Expenses	$       7,158,612	$        7,375,161
Current Portion of Long-Term Debt	233,045	90,746
Deferred Revenue from Turnkey Drilling	5,018,261	6,490,111
Total Current Liabilities	12,409,918	13,956,018
Noncurrent Liabilities:
Asset Retirement Obligation	273,049	245,627
Deferred Tax Liability	1,673,922	3,892,048
Long-Term Debt, Net of Current Portion	3,810,000	6,630,598
Total Noncurrent Liabilities	5,756,971	10,768,273
Total Liabilities	18,166,889	24,724,291
Redeemable Preferred Stock
Series A, Convertible Preferred Stock, No Par Value,
259,250 Shared Authorized; -0- and 6,122 Shares
Issued and Outstanding, Respectively	-	11,589
Stockholders' Equity
Common Stock, No Par Value, 10,000,000 Shares        Authorized; 7,951,748 and 7,948,688 Shares Issued;        7,916,408 and 7,934,736 Outstanding, Respectively	19,511,963	19,500,374
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)	(3,964,439)	(1,314,738)
Total Paid in Capital and Accumulated Deficit	15,715,503	18,353,615
Less Cost of Treasury Stock, 35,340 and 13,952 Shares	(192,052)	(68,271)
Paid in Capital, Treasury Stock	24,863-	21,357
Total Stockholders' Equity	15,548,314	18,318,290
Total Liabilities and Stockholders' Equity	$33,715,203	$      43,042,581

35

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

ROYALE ENERGY, INC.

STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005, AND 2004

	2006	2005	2004
Revenues
Sale of Oil and Gas	$   7,965,633	$ 11,228,537	$ 10,892,574
Turnkey Drilling	15,711,550	13,066,800	13,269,996
Supervisory Fees and Other	1,218,860	1,348,041	1,781,786
Total Revenues	$24,896,043	$ 25,643,378	$ 25,944,356
Costs and Expenses:
General and Administrative	5,129,074	4,877,168	4,925,321
Geological and Geophysical Expenses	400,306	381,790	321,983
Turnkey Drilling Development	9,628,394	8,111,248	8,150,338
Lease Operating	1,968,269	2,751,441	2,817,448
Lease Impairment	6,191,417	742,642	51,414
Legal and Accounting	397,575	236,199	627,038
Marketing	1,799,088	2,222,859	1,564,678
Depreciation, Depletion and Amortization	5,833,904	4,062,587	3,714,271
Total Costs and Expenses	$ 31,348,027	$ 23,385,934	$ 22,172,491
Gain on Sale of Assets	3,263,368	-	-
Income (Loss) from Operations	$  (3,188,616)	$  2,257,444	$   3,771,865
Other Expense:
Interest Expense	523,139	444,271	273,050
Income (Loss) Before Income Tax Expense	(3,711,755)	1,813,173	3,498,815
Income Tax Expense (Benefit)	(1,062,054)	627,270	1,306,063
Net Income (Loss)	$(2,649,701)	$  1,185,903	$  2,192,752
Basic Earnings Per Share:
Net Income (Loss) Available To Common      Stock	$          (0.33)	$          0.15	$           0.32
Diluted Earnings (Loss) Per Share	$          (0.33)	$          0.15	$           0.31

36

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

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005, AND 2004

	Common Stock		Preferred Stock Series AA
	Shares		Shares
	Issued	Amount	Outstanding	Amount
Balance at January 1, 2004	5,621,829	$ 19,108,978	43,240	$         163,926
3.75% Stock Dividend	221,049	755,280	1,619	4,053
28% Stock Dividend	1,712,093	-	12,557	-
Royale Petroleum Corp. - Stock Reorganization.	295,801	-	-	-
Acquisition of Royale Petroleum Corp.	451	5,377	-	-
Stock Options Repurchased	-	(286,356)	-	-
Stock Options Exercised	8,000	7,760	-	-
Net Income (Loss) for the Year	-	-	-	-
Balance at December 31, 2004	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

37

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

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005, AND 2004

	Preferred Stock Series A
	Shares		Accumulated
	Outstanding	Amount	Deficit
Balance at January 1, 2004	4,611	$     11,172	$  (4,693,393)
3.75% Stock Dividend	172	417	-
28% Stock Dividend	1,339	-	-
Royale Petroleum Corp - Stock Reorganization	-	-	-
Acquisition of Royale Petroleum Corporation	-	-	-
Stock Options Repurchased	-	-	-
Stock Options Exercised	-	-	-
Net Income (Loss) for the Year	-	-	2,192,752
Balance at December 31, 2004	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)

38

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

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005, AND 2004

	Treasury Stock
	Shares		Paid in Capital	Dividend to be
	Acquired	Amount	Treasury Stock	Distributed	Total
Balance at January 1, 2004	20,000	$     (97,906)	$        16,761	$      759,750	$   15,269,288
3.75% Stock Dividend Distributed	-	-	-	(759,750)	-
28% Stock Dividend
Royale Petroleum Corp. - Stock Reorganization	-	-	-	-	-
Acquisition of Royale Petroleum Corp.	-	-	-	-	5,377
Stock Options Repurchase	-	-	-	-	(286,356)
Stock Options Exercised	-	-	-	-	7,760
Net Income (Loss) for the Year	-	-	-	-	2,192,752
Balance at December 31, 2004	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

39

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

ROYALE ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2006 2005 AND 2004

	2006	2005	2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ (2,649,701)	$  1,185,903	$ 2,192,752
Adjustments to Reconcile Net Income to Net
Cash Provided by Operating Activities:
Depreciation, Depletion, and Amortization	5,833,904	4,062,587	3,714,271
Lease Impairment	6,191,417	742,642	51,414
Gain on Sale of Assets	(3,263,368)	-	-
Bad Debt Expense	582,204	401,691	641,079
Compensation Expense - Stock Grant	26,105	34,231
(Increase) Decrease in:
Accounts Receivable	586,727	(719,351)	598,471
Prepaid Expenses and Other Assets	(20,645)	1,997,055	(2,409,983)
Increase (Decrease) in:
Accounts Payable and Accrued Expenses	(189,127)	(2,273,741)	875,473
Deferred Revenues - DWI	(1,471,850)	1,210,694	1,244,536
Deferred Income Taxes	(2,219,273)	(246,269)	1,110,287
Net Cash Provided by Operating Activities	3,406,393	6,395,442	8,018,300
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures For Oil And Gas Properties And      Other Capital Expenditures	(3,091,316)	(9,888,809)	(6,915,103)
Proceeds from Sale of Investments	-	-	275,000
Proceeds from Sale of Assets	5,024,054	-	-
Net Cash Provided (Used) by Investing Activities	1,932,738	(9,888,809)	(6,640,103)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt	2,115,000	13,777,500	12,387,500
Principal Payments on Long-Term Debt	(4,793,299)	(13,103,741)	(10,729,914)
Exercise of Options for Cash	-	98,247	-
Repurchase of Stock Options	-	(188,912)	(286,356)
Net Cash Provided (Used) by Financing Activities	(2,678,299)	583,094	1,371,230
Net Increase (Decrease) in Cash and Cash Equivalents	2,660,832	(2,910,273)	2,749,427
Cash & Cash Equivalents at Beginning of Year	4,716,772	7,627,045	4,877,618
Cash & Cash Equivalents at End of Year	$  7,377,604	$  4,716,772	$ 7,627,045

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

ROYALE ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2006 2005 AND 2004 (Continued)

	2006	2005	2004
SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:
Cash Paid for Interest	$529,940	$290,367	$211,633
Cash Paid for Taxes	$259,006	$369,063	$601,523
SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING   & FINANCING ACTIVITIES:
Acquisition of Treasury Stock in Lieu of Receivables Owed	$146,380	$           -	$           -

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

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

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. Actual results could differ from those 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, 2006 and 2005 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

42

production at December 31, 2006, 2005 and 2004 were not significant.

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 co mputed 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 aggr egate 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 $6,191,417, $742,642, and $51,414, were recorded in 2006, 2005, and 2004 respectively.

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

43

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 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.

In 2004, we determined that an impairment was appropriate in the Afton field, which was acquired in 2004, due to a delay in drilling exploratory wells in the field as a result of pipeline restrictions. In addition, we recorded an impairment for the Elkhorn Slough field due to cost overruns on our Kingfisher well due to mechanical problems while completing it.

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, 2004, 2005 and 2006,

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 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.

At December 31, 2006 and 2005, net accounts receivable was $2,906,290 and $4,221,601 respectively. At December 31, 2006 and 2005, the Company established an allowance for uncollecteable accounts of $567,000 and $401,691, respectively for receivables from direct working interest investors whose expenses on non-producing wells was unlikely to be collected from revenue.

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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 (SFAS 128)

Basic and diluted earnings (loss) per share are calculated as follows:

	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)

	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

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	For the Year Ended December 31, 2004
	Income	Shares	Per-Share
	(Numerator)	(Denominator)	Amount
Basic Earnings Per Share:
Net income available to common stock	$   2,192,752	6,900,334	$         0.32
Diluted Earnings Per Share:
Effect of dilutive securities and stock options	-	148,938	(0.01)
Net income available to common stock	$   2,192,752	7,049,272	$        0.31

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.

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:

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	2006	2005	2004
Net income (loss), as reported	$(2,649,701)	$    1,185,903	$    2,192,752
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	$(2,649,701)	$    1,185,903	$    2,192,752
Earnings per share:
Basic -- as reported	$         (0.33)	$            0.15	$            0.32
Basic -- pro forma	$         (0.33)	$            0.15	$            0.32
Diluted -- as reported	$         (0.33)	$            0.15	$            0.31
Diluted -- pro forma	$         (0.33)	$            0.15	$            0.31

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 4,612 and 6,048 shares of vested restricted common stock were issued in 2006 and 2005, respectively. The Company recognized $26,105 and $34,241 compensation expense in 2006 and 2005, respectively. Additionally, 7,490 shares of unvested stock were awarded with vesting dates in 2007 for which compensation expense will be similarly recognized. 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 2006, 2005, or 2004.

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.

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.

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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 November 2005, the FASB issued SFAS No. 151, "Inventory Costs," and amendment of ARB No. 43, Chapter 4. SFAS 151 clarifies the language in ARB 43 and IAS 2 in order to promote consistent application of the standards. This new statement requires inventories to be stated at cost but that unallocated overheads, abnormal freight, handling and spoilage are treated as current period charges instead of as part of inventory costs. This statement becomes effective for fiscal years beginning after June 15, 2005. We do not expect adoption of this statement to materially affect the Company's financial position, results of operations, or cash flows.

In December of 2005, the FASB approved SFAS No. 152, "Accounting for Real Estate Time-Sharing Transactions." This statement amends FASB statements No. 66 and 67 to include changes in the real-estate industry that have occurred since the original statements were adopted. Specifically, SFAS 152 addresses time-sharing interests. This statement is effective for fiscal years beginning after June 15, 2005. Since the Company does not own any time-sharing real estate interests, we do not expect this statement to materially affect the Company's financial position, results of operations, or cash flows.

In December of 2005, the FASB approved SFAS No. 153, "Exchange of Nonmonetary Assets". This statement amends APB Opinion No. 29, eliminating the exception for nonmonetary exchanges of similar productive assets. The prior exception is replaced by an exception for the nonmonetary exchange of assets that will not significantly affect the future cash flows of the entity. This should result in financial statements that more accurately show the economics of the exchange. Specific to the oil and gas industry, gain or loss shall not be recognized at the time of the transaction in the pooling of assets designed to find, develop, or product oil or gas. This statement is effective for fiscal periods beginning after June 15, 2005. We do not expect this statement to materially affect the Company's financial position, results of operations, or cash flows.

In February 2006, the FASB issued Statement of Financial Accounting Standards No. 155 (SFAS 155) "Accounting for Certain Hybrid Instruments - an amendment of FASB Statements No. 133 and 140." SFAS 155 amends SFAS 133 to permit fair value measurement for certain hybrid financial instruments that contain an embedded derivative, provides additional guidance on the applicability of SFAS 133 and SFAS 140 to certain financial instruments and subordinated concentrations of credit risk. SFAS 155 is effective for the first fiscal year that begins after September 15, 2006. We do not expect this statement to materially affect the Company's financial position, results of operations, or cash flows.

In July 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48 "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109" (FIN 48,) which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the effects from an uncertain tax position can be recognized in the financial statements only if the position is "more-likely-than-not" of being sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the "more-likely-than-not" threshold, the largest amount of tax benefit that is greater than 50 percent likely of being recognized upon

48

ultimate settlement with the taxing authority, is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We do not expect this statement to materially affect the Company's financial position, results of operations, or cash flows.

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. The Company is 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.

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NOTE 2 -OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

Oil and gas properties, equipment and fixtures consist of the following at December 31,:

	2006	2005
Oil and Gas
Producing properties, including intangible drilling costs	$  27,876,284	$  28,805,150
Undeveloped properties	1,767,671	6,232,050
Lease and well equipment	7,136,142	8,777,597
	36,780,097	43,814,797
Accumulated depletion, depreciation and amortization	(17,745,105)	(14,743,316)
	$19,034,992	$ 29,071,481
Commercial and Other
Real estate, including furniture and fixtures	503,344	503,344
Vehicles	287,155	255,523
Furniture and equipment	1,702,127	2,391,490
	2,492,626	3,150,357
Accumulated depreciation	(1,001,658)	(1,001,187)
	1,490,968	2,149,170
	$20,525,960	$ 31,220,651

The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed:

	2006	2005	2004
Acquisition - Proved	$       720,796	$       394,069	$    3,217,409
Acquisition - Unproved	$    1,276,429	$       848,358	$    1,906,106
Development	$    7,489,178	$    7,633,536	$    2,388,723
Exploration	$    5,727,865	$    5,507,658	$    7,925,775

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 performed an evaluation of our capitalized costs and determined that no previously capitalized exploratory well costs pending the determination of proved reserves were required to be expensed or reclassified during 2006 or 2005. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2006 or 2005. We did not charge any previously capitalized exploratory well costs to expense upon adoption of FSP FAS 19-1.

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	12 Months Ended December 31,
	2006	2005
Beginning balance at January 1	$                   0	$                   0
Additions to capitalized exploratory well costs pending the determination of proved reserves	$     1,852,733	$     2,276,495
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	$    (1,852,733)	$    (2,276,495)
Ending balance at December 31	$                   0	$                   0

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:

	2006	2005	2004
Oil and gas sales	$    7,965,633	$   11,228,537	$   10,892,574
Production related costs	(1,968,269)	(2,751,441)	(2,817,448)
Geological and geophysical expense	(400,306)	(381,790)	(321,983)
Lease Impairment	(6,191,417)	(742,642)	(51,414)
Depreciation, depletion and amortization	(5,833,904)	(4,062,587)	(3,714,271)
Results of operations from producing and
exploration activities	$   (6,428,263)	$    3,290,077	$    3,987,458
Income Taxes (Benefit)	(2,217,751)	1,135,077	1,375,673
Net Results	$   (4,210,512)	$    2,155,000	$    2,611,785

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 acquis ition, development, and operation of a long-lived asset.

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	2006	2005
Asset retirement obligation
Beginning of the year	$245,627	$266,462
Liabilities incurred during the period	24,811	21,007
Settlements	(6,520)	(14,026)
Accretion expense	9,450	10,050
Revisions in estimated cash flow	(319)	(37,866)
Asset retirement obligation
End of year	$273,049	$245,627

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, 2006 and 2005, Royale Energy had recorded deferred turnkey drilling revenue associated with undrilled wells of $5,018,261 and $6,490,111, respectively, as a current liability.

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 2006, 2005, and 2004:

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	Oil and Gas
	Producing	Turnkey
	and	Drilling
	Exploration	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	$  3,095,709	$   3,095,708	$   6,191,417
Gain on Sale of Assets	$  3,263,368	$                  -	$   3,263,368
Income Tax	$    (531,027)	$     (531,027)	$  (1,062,054)
Total Assets	$ 33,715,203	$                  -	$ 33,715,203
Net Income (Loss)	$  (1,549,898)	$  (1,099,803)	$  (2,649,701)

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	Oil and Gas Producing And Exploration	Turnkey DrillingServices	Total
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	$       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
Year Ended December 31, 2004
Revenues from External Customers	$   10,892,574	$  13,269,996	$  24,162,570
Supervisory Fees	$     1,712,673	$                   -	$    1,712,673
Interest Revenue	$          69,113	$                   -	$         69,113
Interest Expense	$        136,525	$       136,525	$       273,050
Expenditures for Segment Assets	$     6,580,446	$  11,826,360	$  18,406,806
Depreciation, Depletion, and Amortization	$     3,528,557	$       185,714	$    3,714,271
Lease Impairment	$          25,707	$         25,707	$         51,414
Income Tax (Benefit)	$        653,031	$       653,032	$    1,306,063
Total Assets	$   42,548,669	$                   -	$  42,548,669
Net Income (Loss)	$     1,718,987	$       473,765	$    2,192,752

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NOTE 6 -LONG-TERM DEBT

	2006	2005
Revolving line of credit secured by oil and gas properties, with a maximum available of $3,820,974 at December 31, 2006 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 8.75% and 7.75% at December 31, 2006 and 2005, respectively, payable monthly with borrowing base reductions of $250,000 commencing on February 1, 2007. All unpaid principal and interest is payable at maturity on June 1, 2008.	$3,810,000	$6,400,000
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 with all unpaid principal and interest due on March 17, 2007.	$   233,045	$   321,344
Total Long Term Debt	$4,043,045	$6,721,344
Less Current Maturity	$(233,045)	$(90,746)
Long Term Debt Less Current Portion	$3,810,000	$6,630,598

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 the terms of this agreement at December 31, 2006 and 2005.

Maturities of long-term debt for years subsequent to December 31, 2006 are as follows:

Year Ended
December 31,
2007	$     233,045
2008	$  3,810,000
	$  4,043,045

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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.

Significant components of the Company's deferred assets and liabilities at December 31, 2006, 2005 and 2004, respectively, are as follows:

	2006	2005	2004
Deferred Tax Assets (Liabilities):
Statutory Depletion Carry Forward	$       129,433	$       816,270	$       816,270
Capital Loss / AMT Credit Carry Forward	22,465	25,311	133,023
Charitable Contributions Carry Forward	-	6,660	-
Allowance for Doubtful Accounts	195,615	124,097	206,045
Oil and Gas Properties and Fixed Assets	(1,825,820)	(4,669,918)	(4,138,317)
Net Deferred Tax Liability	$   (1,478,307)	$   (3,697,580)	$   (2,982,979)
Deferred Tax Assets:
Current	195,615	194,468	1,155,338
Non-current	-	-	-
Deferred Tax Liabilities:
Current	-	-	-
Non-current	(1,673,922)	(3,892,048)	(4,138,317)
Net Deferred Tax Liability	$   (1,478,307)	$   (3,697,580)	$   (2,982,979)

The Company had statutory percentage depletion carry forwards of approximately $375,168 and $2,366,000 at December 31, 2006 and 2005 respectively. The depletion has no expiration date. The Company also had no capital loss carryforward at December 31, 2006 and 2005, respectively.

A reconciliation of Royale Energy's provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2006, 2005 and 2004, respectively, to pretax income is as follows:

	2006	2005	2004
Tax (benefit) computed at statutory rate	$     (1,279,100)	$       625,440	$     1,207,874
Increase (decrease) in taxes resulting from:
State tax / percentage depletion / other	211,712	-	93,987
Other non deductible expenses	5,334	1,830	4,202
Provision (benefit)	$     (1,062,054)	$       627,270	$     1,306,063
Effective Tax Rate	28.6%	34.6%	37.3%

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The components of the Company's tax provision are as follows:

	2006	2005	2004
Current tax provision (benefit) - federal	$     915,010	$       5,570	$       125,003
Current tax provision (benefit) - state	242,209	629	14,113
Deferred tax provision (benefit) - federal	(1,754,774)	558,064	1,048,561
Deferred tax provision (benefit) - state	(464,499)	63,007	118,386
Total provision (benefit)	$(1,062,054)	$627,270	$1,306,063

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 or 2004. 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.

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, 2006 and 2005, there were 57,416 shares issued and outstanding.

NOTE 10 -COMMON STOCK

On March 23, 2004, the Board of Directors declared a 28% stock splitissued 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, 2006 or 2005.

NOTE 11 -SUBSEQUENT EVENTS

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 $397,049.05.

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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, 2006 are as follows:

Year Ended
December 31,
2007	$        338,520
2008	348,689
2009	358,857
2010	369,555
2011	380,465
Thereafter	1,458,307
Total	$    3,254,393

Rental expense for the years ended December 31, 2006, 2005, and 2004 are $370,658, $340,006, and $298,165, respectively.

NOTE 13 -RELATED PARTY TRANSACTIONS

Significant Ownership Interests

Donald H. Hosmer, Royale Energy's president, owns 12.51% 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 14.71% 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 9.93% 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 outside directors were billed $49,787, $130,473 and $196,323 for their interests for the three years ended December 31, 2006, 2005, and 2004 respectively. Current affiliated directors were billed $183,053, $325,874 and $409,086 for their interests for the three years ended December 31, 2006, 2005, and 2004 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.

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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.

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 2006, 2005, or 2004.

On March 26, 2001, the number of options increased from 30,000 to 34,500 and the price decreased from $3.00 per share to $2.60 per share due to the declaration of the 15% stock dividend.

On March 18, 2002, the number of remaining options of 113,850 decreased to 104,478 outstanding and the price decreased from $1.65 per share to $0.83 per share due to expiration of options and the declaration of the 15% stock dividend.

On May 1, 2003, the number of remaining options of 104,478 increased to 114,439 outstanding and the price increased from $0.83 per share to $1.79 per share due to the reinstatement of shares, repurchase of options from employees/directors and the declaration of the 15% stock dividend, which is being paid in equal quarterly installments.

On July 10, 2003, the Company repurchased 10,290 options from Don Hosmer in the amount of $59,270, and 42,000 options from Harry Hosmer amounting to $275,854.

On March 29, 2004, the Company repurchased 14,063 options from Harry Hosmer amounting to $160,178, and 11,078 options from Don Hosmer amounting to $126,178.

On June 24, 2005, the Company repurchased 19,615 options from Stephen Hosmer amounting to $188,912.

A summary of the status of Royale Energy's stock option plan as of December 31, 2006, 2005 and 2004, and changes during the years ending on those dates is presented below:

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	2006		2005		2004
		Weighted-		Weighted-		Weighted-
		Average		Average		Average
		Exercise		Exercise		Exercise
	Shares	Price	Shares	Price	Shares	Price
Fixed Options
Outstanding at Beginning of Year	0	-	137,143	$1.13	114,439	$1.51
Stock Dividends and Splits	-		-		35,849
Reinstated	-		-		19,996
Exercised	-		(109,686)		(33,141)
Expired or Ineligible	-		(27,457)		-
Outstanding at End of Year	0	-	0	$0.97	137,143	$1.13
Options Exercisable at Year End	-	-	-	$0.97	137,143	$1.13
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, 2006, 2005, and 2004 were $48,986, $48,445 and $46,043, respectively.

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 2006, 2005, or 2004.

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 75% of its monthly natural gas production to one customer on a month to month basis.

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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, 2006 and 2005, cash in banks exceeded the FDIC limits by approximately $8.1 and $6.5 million, respectively. The Company has not experienced any losses on deposits.

NOTE 18 : Quarterly Financial Information (Unaudited):

	First Quarter	SecondQuarter	ThirdQuarter	FourthQuarter	Total Year
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)
2005
Revenues	$ 5,552,615	$6,059,735	$6,449,816	$ 7,581,212	$25,643,378
Operating income (loss)	(17,606)	402,494	445,675	1,426,881	2,257,444
Net income (loss)	$  (131,833)	$   264,071	$   211,584	$    842,081	$  1,185,903
Earnings (loss) per share
Basic and Diluted	$        (0.02)	$         0.03	$         0.03	$          0.11	$           0.15

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.

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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, 2006, 2005, and 2004. 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, 2006, 2005 and 2004 and changes in such quantities during each of the years then ended, were as follows:

	2006		2005		2004
	Oil (BBL)	Gas (MCF)	Oil (BBL)	Gas (MCF)	Oil (BBL)	Gas (MCF)
Proved developed and undeveloped reserves:
Beginning of period	91,000	10,564,000	317,000	12,624,000	158,000	11,850,000
Revisions of previous estimates	(34,444)	(1,022,969)	(104,235)	(1,013,667)	(44,488)	(1,935,378)
Production	(21,325)	(1,074,573)	(16,557)	(1,384,860)	(20,017)	(1,870,250)
Extensions, discoveries and improved recovery	2,331	1,866,918	9,000	1,952,299	233,890	4,482,054
Purchase of minerals in place	0	0	-	-	-	633,593
Sales of minerals in place	(563)	(2,173,376)	(114,208)	(1,613,772)	(10,385)	(536,019)
Proved reserves end of period	37,000	8,160,000	91,000	10,564,000	317,000	12,624,000

	2006		2005		2004
	Oil (BBL)	Gas (MCF)	Oil (BBL)	Gas (MCF)	Oil (BBL)	Gas (MCF)
Proved developed reserves:
Beginning of period	65,000	6,990,000	146,000	8,135,000	137,000	9,390,000
End of period	37,000	4,129,000	65,000	6,990,000	146,000	8,135,000

These estimates were determined using gas prices at December 31, 2006 ranging from $5.25 per MCF to $8.66 per MCF as applied on a field-by-field basis.

In 2004, the discontinuation of one well and significant downward revision of a second well accounted for downward revisions of more than 1.14 million cubic feet of proved developed reserves, which is 77% of the net revisions in 2004. Both wells had been producing gas wells. The reserve estimate for one well was revised downward by 622,928 cubic feet to 0, and the reserve estimate of the second well was revised downward by 521,714 cubic feet to 182,000 cubic feet.

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, 2006.

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:

2007	$     6,937,000
2008	3,760,000
2009	10,000
Thereafter	72,000
Total	$   10,779,000

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.

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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.

	2006	2005	2004
Future cash inflows	55,931,000	95,339,000	91,215,000
Future production costs	(11,628,000)	(18,086,000)	( 16,029,000)
Future development costs	(10,779,000)	(  9,416,000)	(   8,465,000)
Future income tax expense	(10,057,200)	(20,351,400)	( 20,016,153)
Future net cash flows	23,466,800	47,485,600	46,704,847
10% annual discount for estimated timing of cash flows	(  6,820,249)	(12,682,159)	( 12,423,729)
Standardized measure -of discounted future net cash flows	16,646,551	34,803,441	34,281,118
Sales of oil and gas produced, net of production costs	(  4,745,695)	( 7,022,572)	(  6,766,942)
Revisions of previous quantity estimates	( 15,871,556)	( 2,814,698)	(  4,282,365)
Net changes in prices and production costs	(   4,015,314)	1,269,384	5,498,228
Sales of minerals in place	(   7,906,688)	( 3,947,974)	(  2,754,216)
Purchases of minerals in place	-	-	2,009,099
Extensions, discoveries and improved recovery	4,216,939	8,593,335	17,595,769
Accretion of discount	2,383,900	4,668,700	3,224,700
Net change in income tax	7,781,524	(    223,852)	( 4,357,282)
Net increase (decrease)	(18,156,890)	522,323	10,166,991

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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 2007 through 2009.

Future development cost of:	2007	2008	2009
Proved developed reserves	$       71,000	$           -	$           -
Proved non-producing reserves	18,000	51,000	10,000
Proved undeveloped reserves	6,848,000	3,709,000	$           -
Total	$  6,937,000	$  3,760,000	$      10,000

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, 2006, 2005, and 2004, 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:

2006	$2,492,985
2005	$2,428,069
2004	$2,881,835

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