ROYALE ENERGY INC - 10-K Annual Report

As filed with the SEC on April 15, 2005

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, 2004		Commission File No. 0-22750

ROYALE ENERGY, INC.

(Name of Small Business Issuer 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

(Title of Class)

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. [ ]

State issuer's revenues for its most recent fiscal year: $25,944,356.

At December 31, 2004, there were 4,815,962 outstanding shares of registrant's Common Stock held by non-affiliates, with an aggregate market value of approximately $34,674,926 based on the closing Nasdaq price on that date.

At December 31, 2004, a total of 7,839,223 shares of registrant's Common Stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

Exhibit Index appears on page 27.

TABLE OF CONTENTS

Part I		1
Item 1.	Description of Business	1
	Plan of Business	2
	Competition, Markets and Regulation	4
Item 2.	Description of Property	5
	Northern California	5
	Developed and Undeveloped Leasehold Acreage	6
	Drilling Activities	6
	Production	7
	Net Proved Oil and Natural Gas Reserves	7

Part II		8
Item 5.	Market Price of Royale Energy's Common Stock and Related Stockholder Matters	8
	Dividends	8
	No Recent Sales of Equity Securities	8
Item 6	Selected Financial Data	9
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	9
	Critical Accounting Policies	9
	Results of Operations for the Twelve Months Ended December 31, 2004, as Compared to the Twelve Months Ended December 31, 2003	11
	Results of Operations for the Twelve Months Ended December 31, 2003, as Compared to the Twelve Months Ended December 31, 2002	14
	Capital Resources and Liquidity	17
Item 7A	Qualitative and Quantitative Disclosures About Market Risk	18
Item 8.	Financial Statements	19
Item 9A	Disclosure Controls and Procedures	19

Part III		20
Item 10.	Directors and Executive Officers of the Registrant	20
	Compliance with Section 16(a) of the Exchange Act	22
Item 11.	Executive Compensation	22
	No Stock Options Were Granted in 2004	23
	Aggregate 2004 Option Exercises and Year-End Values	23
	Performance Graph	24
	Compensation of Directors	24
Item 12.	Security Ownership of Certain Beneficial Owners and Management	24
	Common Stock	24
	Preferred Stock	25
Item 12.	Certain Relationships and Related Transactions	26
Item 13.	Exhibits	27
Item 14	Principal Accountant Fees and Services	27
Signatures		28
Financial Statements		F-1

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 March 1, 2005, 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 permits 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, 2004, 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 14 wells in 2004, 7 of which are currently commercially productive wells. Two wells are waiting on completion. Royale Energy's estimated total reserves increased from approximately 13.4 Bcfe (billion cubic feet equivalent) at December 31, 2003 to approximately 15.8 Bcfe at December 31, 2004. 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 $46.7 million at December 31, 2004, based on natural gas prices ranging from $5.38 per Mcf to $6.57 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. The engineer determined our standard measure of discounted future net cash flows at December 31, 2004, to be $34,281,118.

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 $13,269,996 for the year ended December 31, 2004, which represents 51.1% of its total revenues for the year. In 2003, Royale Energy reported $11,966,860 gross revenues from turnkey drilling operations for the year, representing 51.4% of Royale Energy's total revenues for that year.

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These amounts are offset by drilling expenses and development costs of $8,150,338 in 2004, and $5,855,661 in 2003. In addition to Royale Energy's own engineering staff, Royale Energy hires independent contractors to drill, test, complete and equip the wells that it drills.

Approximately 42.0% of Royale Energy's total revenue for the year ended December 31, 2004 came from sales of oil and natural gas from production of its wells in the amount of $10,892,574. In 2003, this amount was $10,120,148, which represented 43.5% of Royale Energy's total revenues.

Plan of Business

Royale Energy acquires interests in oil and natural gas reserves and sponsors private joint ventures. Royale Energy believes that its shareholders 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 is called a "turnkey contract." When Royale Energy sells fractional interests to raise capital to drill oil and natural gas wells, generally it agrees to drill these wells on a turnkey contract basis, so that the holders of the fractional interests prepay a fixed amount for the drilling and completion of a specified number of wells. Under a turnkey contract, Royale 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

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remaining investment is held and reported by Royale Energy as deferred revenue until the well is spudded (begun). Drilling is generally completed within 7 - 14 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, 2004, Royale Energy earned gross revenues from operation of the wells in the amount of $487,406, representing 1.8% of its total revenues on a consolidated basis for that year. In 2003, the amount was $433,653, which represented about 1.9% of total revenues. As of December 31, 2004, Royale Energy holds working interests in 66 gas wells and one oil well in California, with locations ranging from Tehama County in the north to Kern County in the south. We also own working interests in 2 producing wells in offshore Louisiana and 12 producing wells in Texas. We also hold a minority interest in one producing gas well in Oklahoma.

Royale Energy currently sells all of its California natural gas production through PG&E pipelines to independent customers on a monthly contract basis. 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.

Natural gas demand and the prices paid for gas are seasonal. In recent years, natural gas demand and prices in Northern California have decreased during the fall and winter and risen in the spring and summer, reflecting increased electricity consumption.

Royale Energy had no subsidiaries in 2004.

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.

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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 legislation and regulations, together with any penalties resulting from failing to comply with the legislation and regulations. Ultimately, Royale Energy may bear s ome 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

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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 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 2004, Royale Energy drilled nine wells in northern and central California, five of which were commercially productive wells. Four are currently producing and one well is waiting on pipeline to be completed. Royale Energy also participated in drilling five wells in Texas, four of which were commercially productive. Three are currently producing and one is waiting on completion.

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

Royale Energy maintains a revolving credit agreement with Guaranty Bank, FSB. Under the terms of the agreement, from time to time, Royale Energy may borrow, repay, and reborrow money from Guaranty Bank with a total credit line of $15,000,000. The maximum allowable amount of each credit request is governed by a formula in the agreement. The maximum allowable amount at December 31, 2004, was $5,472,500. At December 31, 2004, Royale Energy owed $5,472,500 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, 2004, 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 February 10, 2005 (the most recent report available).

Northern California

Royale Energy owns lease interests in 15 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 northern California. At December 31, 2004, Royale Energy operated 68 wells in Northern and Central California, and its estimated total proved developed and undeveloped reserves in Northern and Central California were approximately 8.1 Bcfe, according to Royale Energy's independently prepared reserve report.

Developed and Undeveloped Leasehold Acreage

As of December 31, 2004, Royale Energy owned leasehold interests in the following developed

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and undeveloped properties in both gross and net acreage.

	Developed		Undeveloped
	Gross Acres	Net Acres	Gross Acres	Net Acres
California	16,844.58	9,803.43	14,934.08	11,534.47
All Other States	8,558.99	4,881.10	24,148.94	14,009.69
Total	25,403.57	14,684.53	39,083.02	25,544.16

Drilling Activities

The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2002, 2003 and 2004. All wells are located in the Continental U.S., in California, Texas, Louisiana and Utah.

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

2002	Exploratory	8	5	3	1.5663	2.2042
	Developmental	8	8	-	3.1663	-

2003	Exploratory	3	2	1	1.0502	.4061
	Developmental	14	13	1	4.6311	.4750

2004	Exploratory	10	6	4	1.6408	1.9175
	Developmental	4	3	1	0.8390	0.0371

^{(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.}

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As of December 31, 2004, Royale Energy operated 66 producing natural gas wells and one producing oil well maintaining approximately 50% interest. One well was currently drilling and two wells were waiting on pipeline. Royale also maintained approximately 36% interest in 14 additional wells, which are outside operated.

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.

	2004	2003	2002
Net volume
Oil (Bbl)	20,017	23,411	8,085
Gas (Mcf)	1,870,250	1,944,779	1,602,780
Mcfe	2,070,420	2,178,889	1,683,630

Average sales price
Oil (Bbl)	$ 36.66	$ 28.00	$ 22.84
Gas (Mcf)	$ 5.43	$ 4.86	$ 2.95

Net production costs and taxes	$2,817,448	$1,714,382	$ 1,450,893

Lifting costs (per Mcfe)	$ 1.36	$ 0.79	$ 0.86

Net Proved Oil and Natural Gas Reserves

As of December 31, 2004, Royale Energy had proved developed reserves of 8,135 MMcf and total proved reserves of 12,624 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 146 Mbbl and total proved oil reserves of 317 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.

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Item 3 Legal Proceedings

None

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, 2004, 7,839,223 shares of Royale Energy's Common Stock were held by approximately 3,099 shareholders. The following table reflects high and low quarterly closing sales prices from January 2002 through December 2004. Share prices in this table have been adjusted to give effect to the issuance of stock dividends in 2002, 2003 and 2004, and a stock split in 2004, as described in the next subsection, Dividends.

	1^st Qtr		2^nd Qtr		3^rd Qtr		4^th Qtr
	High	Low	High	Low	High	Low	High	Low
2004	10.13	7.14	13.06	9.71	11.90	6.81	9.36	7.02
2003	4.12	3.10	5.44	3.04	5.29	4.40	9.50	4.75
2002	6.90	2.96	7.05	2.77	3.87	2.57	4.03	2.45

Dividends

In March 2004, the board of directors declared a 28% stock split, which was distributed to shareholders on June 30, 2004. In March 2003, Royale Energy's board of directors declared stock dividends of 3.75% payable to shareholders of record on each of the last days June, September and December 2003 and March 2004. Primarily as a result of these dividends, the number of shares of our outstanding common stock has increased from 5,030,101 shares on December 31, 2002, to 5,621,829 shares on December 31, 2003 and to 7,839,223 shares on December 31, 2004 (not including shares that may be issued on the exercise of options and warrants and on the conversion of preferred stock).

No Recent Sales of Unregistered Securities

We sold no shares of equity securities in fiscal 2004. We did issue stock to our existing shareholders pursuant to a stock split and stock dividend as described in the preceding paragraph.

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Item 6 Selected Financial Data

	(In thousands, except earnings per share data) As of December 31,
	2004	2003	2002	2001	2000
Income Statement Data:					(Restated)
Revenues	$25,944	$23,265	$12,440	$15,858	$11,687
Operating income (loss)	3,772	6,854	(87)	4,172	3,257
Net income (loss)	2,193	4,401	(137)	3,757	2,751
Basic earnings per share	0.32	0.71	(0.02)	0.72	0.53

Balance Sheet Data:
Oil & gas properties, equipment & fixtures	$26,137	$22,904	$15,177	$12,226	$11,719
Total assets	42,549	35,671	23,301	19,578	20,778
Long term obligations	10,382	7,614	3,500	2,000	4,952
Total stockholders' equity	17,189	15,269	11,203	11,294	7,518

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

For the past eleven years, Royale Energy has primarily acquired and developed producing and non-producing natural gas properties in Northern California. 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

Royale Energy's financial statements include its pro 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 its pro 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.

Revenue Recognition

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

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revenue portion when the investor deposits money with Royale Energy. The company holds the remaining investment in trust as deferred revenue until the well is spudded (begun). Occasionally, spudding is delayed due to the permitting process, or drilling rig availability. At December 31, 2004 and 2003, Royale Energy had deferred drilling revenue of $5,279,417 and $4,034,881, respectively.

The second business segment is oil and gas production. Northern California accounts for 78% 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.

Royale Energy follows the units of production 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 delay and leasing rents paid, drilling costs, and post-drilling tangible costs. Costs of unproved properties 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.

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-

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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.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, plant products and gas reserve volumes and the future development costs. Actual results could differ from those estimates.

Deferred income taxes 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.

Asset Retirement Obligations - Change in Accounting Principle

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 1 to our Financial Statements - Summary of Significant Accounting Policies - Recently Issued Accounting Pronouncements. Royale Energy adopted the statement as of January 1, 2003. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $157,185 increase in the carrying values of proved properties and a $188,007 increase in noncurrent abandonment liabilities. The net impact of these items was to record $41,301, net of tax, as a cumulative effect adjustment of a change in accounting principle in our Statement of Income for 2003.

Results of Operations for the Twelve Months Ended December 31, 2004, as Compared to the Twelve Months Ended December 31, 2003

For the year ended December 31, 2004, we had a net profit of $2,192,752, a $2,208,168 or 50.2% decrease compared to the net profit of $4,400,920 achieved during 2003. We attribute this to several factors, including increased depletion rates, intensifying marketing efforts, the drilling of deeper oil and natural gas wells and the blowout of the Bowerbank Sam #2 well during the year in 2004.

Total revenues for the year in 2004 were $25,944,356, an increase of $2,679,219 or 11.5% from the total revenues of $23,265,137 in 2003.

In 2004, revenues from oil and gas production increased by 7.6% to $10,892,574 from

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$10,120,148, due to increased natural gas and oil prices. The net sales volume of natural gas for the year ended December 31, 2004, was approximately 1,870,250 Mcf with an average price of $5.43 per Mcf, versus 1,944,779 Mcf with an average price of $4.86 per Mcf for 2003. This represents a decrease in net sales volume of 74,529 Mcf or 3.8%. The net sales volume for oil and condensate (natural gas liquids) production was 20,017 barrels with an average price of $36.66 per barrel for the year ended December 31, 2004, compared to 23,411 barrels at an average price of $28.00 per barrel for the year in 2003. This represents a decrease in net sales volume of 3,394 barrels, or 14.5%.

During the second quarter of 2004, we suffered a blowout of our Bowerbank Sam #2 well during recompletion operations. This is the first blowout to occur on a well operated by us in more than 18 years of operation. Mainly because of the blowout, oil and gas lease operating expenses increased by $1,103,066, or 64.3%, to $2,817,448 for the year ended December 31, 2004, from $1,714,382 for the year in 2003. The increase was also due to the plugging and abandoning of non-producing wells in addition to an increase in workover costs during the year in 2004 when compared to 2003. When measuring lease operating costs on a production or lifting cost basis, in 2004, the $2,817,448 equates to a $1.36 per mcfe lifting cost versus a $0.79 per mcfe lifting cost in 2003, a 73.0% increase. Lifting cost excluding the extraordinary items of the blowout and plugging, was $1.21 per Mcfe. For 2004, our gross margin, or profit, on oil and gas production (excluding drilling and development costs) was 74.1%, compared to 83.1% in 2003.

For the year ended December 31, 2004, turnkey drilling revenues increased $1,303,136, to $13,269,996 in 2004 from $11,966,860 in 2003, or 10.9%. We also had a $2,294,677 or 39.2% increase in turnkey drilling and development costs to $8,150,338 in 2004 from $5,855,661 in 2003. The increase in turnkey drilling revenues was mainly due to an increase in direct working interest sales during the year in 2004 when compared to the year in 2003. The increase in drilling and development costs was due to higher drilling and completion costs of wells drilled in 2004 when compared to 2003 due to the drilling of ten exploratory wells and four developmental in 2004 versus three exploratory wells and fourteen developmental wells in 2003. 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 sel l working interests and to acquire viable properties that can be successfully developed. Costs associated with contract drilling depend on location, well depth, weather, and availability of drilling contractors and equipment. Our gross margin on drilling was 38.6% and 51.1% for the years ended December 31, 2004 and 2003, 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 $51,414 and $869,991 were recorded in 2004 and 2003, respectively. We periodically review for impairment proved properties on a field-by-field basis.

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Unamortized capital costs are measured on a field basis and are reduced to fair value if it is determined that the sum of expected future net cash flows are less than the net book value. We determine if impairment has occurred through either adverse changes or as a result of its periodic review for impairment. Impairment is measured on discounted cash flows utilizing a discount rate appropriate for risks associated with the related properties or based on fair market values. We regard impairment costs 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.

The aggregate of supervisory fees and other income was $1,781,786 for the year ended December 31, 2004, an increase of $603,657 (51.2%) from $1,178,129 during the year in 2003. This was due to an increase in cost recovery received for new facilities constructed and placed into service during the period in 2004, combined with a gain on sale of a non-oil and gas asset in 2004 and the loss on sale of some of our oil and gas assets during the first quarter in 2003. 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 $53,753 or 12.4%, to $487,406 in 2004 from $433,653 in 2003.

Depreciation, depletion and amortization expense increased to $3,714,271 from $2,418,922, an increase of $1,295,349 (53.6%) for the year ended December 31, 2004, as compared to the same period in 2003. 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, $321,983 of previously capitalized costs were written off and recorded as geological and geophysical expense during 2004 compared with $209,622 written off in 2003, a $112,361 or 53.6% increase.

General and administrative expenses increased by $1,211,522 or 30.3%, from $3,993,668 for the year ended December 31, 2003 to $5,205,190 for the year in 2004. This increase was partially due to an allowance for bad debts of approximately $641,000 for receivables from direct working interest investors whose expenses on non-producing wells was unlikely to be collected. We also had increased employee salaries and related expenses, taxes and insurance, due to increased staffing. There were also increases in rents and related costs due to the opening of two new field offices and expansion in our home office space. Legal and accounting expense increased to $627,038 for the period, compared to $544,302 for year 2003, an $82,736 or 15.2% increase. These increases were due to higher audit, tax preparation and legal fees during the year in 2004. Marketing expense for the year ended

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December 31, 2004 increased $480,443, or 59.7%, to $1,284,809, compared to $804,366 for the year in 2003. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

During the period in 2004, we increased long term debt under our commercial bank credit line and obtained a new term loan on non-oil and gas real estate we own, which increased interest expense to $273,050 for the year ended December 31, 2004, from $194,997 for the same period in 2003, a $78,053, or 40.0% increase. The interest rate charged to the company also increased during 2004, from 4.75% at December 31, 2003, to 6.0% at December 31, 2004.

In 2004 our income tax expense decreased to $1,306,063 from $2,217,005 in 2003, a $910,942 or 41.1% decrease, mainly due to the decrease in our net income. For the periods in 2003 and 2004, this represents an effective tax rate of approximately 33.5% and 37.3%, 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%).

As mentioned earlier, in 2003 we adopted SFAS 143 for Asset Retirement Obligations, which resulted in a $41,301, net of tax, cumulative effect adjustment of a change in accounting principle in 2003. There were no adjustments for changes in accounting principle in during 2004.

Results of Operations for the Twelve Months Ended December 31, 2003, as Compared to the Twelve Months Ended December 31, 2002

For the year ended December 31, 2003, we had a net profit of $4,400,920, a $4,537,956 increase compared to the net loss of $137,036 achieved during the year in 2002. Total revenues for the year in 2003 were $23,265,137, an increase of $10,825,249 or 87.0% from the total revenues of $12,439,888 in 2002. We attribute this increase in revenues to an increase in oil and gas sales resulting from increased production and higher natural gas prices received during the year in 2003 when compared to 2002. For the year in 2003, revenues from oil and gas production increased by 105.3% from $4,930,278 to $10,120,148, as natural gas prices in California increased, compared to the prices received in 2002. The net sales volume for the year ended December 31, 2003, was 1,944,779 Mcf with an average price of $4.86 per Mcf, versus 1,602,780 Mcf with an average price of $2.95 per Mcf for 2002, which represents an increase in net sales volume of 342,000 Mcf or 21.3%. The net sales volume for oil and condensate (natural gas li quids) production was 23,411 barrels with an average price of $28.00 per barrel for the period ended December 31, 2003, compared to 8,085 barrels at an average price of $22.84 per barrel for the same period in 2002, which represents an increase in net sales volume of 15,326 barrels or 189.6%

Oil and gas lease operating expenses increased by 18.2% or $263,489, to $1,714,382 for the year ended December 31, 2003, from $1,450,893 for the same period in 2002, primarily due to an increase in the number of wells placed into production during 2003 when compared to

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2002, due to successful wells being drilled. In addition, there was an increase in the number of existing wells which required workovers to be performed in 2003 when compared to 2002. When measuring lease operating costs on a production or lifting cost basis, in 2003, the $1,714,382 equates to a $0.79 per mcfe lifting cost versus a $0.86 per mcfe lifting cost in 2002, an 8.1% decrease. We were able to reduce lifting costs in 2003 by hiring employees to conduct our lease operations instead of contracting with third party lease operators. For 2003, our gross margin, or profit, on oil and gas production (excluding drilling and development costs) was 83.1%, compared to 70.6% in 2002.

For the year ended December 31, 2003, turnkey drilling revenues increased $5,076,429, to $11,966,860 in 2003 from $6,890,431 in 2002, or 73.7%. We also had a $1,699,422 or 40.9% increase in turnkey drilling and development costs from $4,156,239 in 2002 to $5,855,661 in 2003. This increase in turnkey revenues and costs was partially due to drilling seventeen wells during the year in 2003 while we drilled sixteen during the year in 2002. In addition, we also had in increase in direct working interest sales during the year in 2003 when compared to 2002. 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 51.1% and 39.7% for the years ended December 31 , 2003 and 2002, 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 $869,991 and $596,222 were recorded in 2003 and 2002, respectively. We periodically review for impairment proved properties on a field-by-field basis. Unamortized capital costs are measured on a field basis and are reduced to fair value if it is determined that the sum of expected future net cash flows are less than the net book value. We determine if impairment has occurred through either adverse changes or as a result of its periodic review for impairment. Impairment is measured on discounted cash flows utilizing a discount rate appropriate for risks associated with the related properties or based on fair market values. We regard impairment costs 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.

The aggregate of supervisory fees and other income was $1,178,129 for the year ended December 31, 2003, an increase of $558,950 (90.3%) from $619,179 during 2002. This increase was mainly due to an increase in cost recovery received for new facilities constructed and placed into service during the year in 2003 when compared to 2002. 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

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and adjusted up or down as deemed appropriate by a published report to the industry by Ernst & Young, LLP, Public Accountants. Supervisory fees decreased $8,861 or 2.0%, from $442,514 in 2002 to $433,653 in 2003.

Depreciation, depletion and amortization expense increased to $2,418,922 from $1,694,027, an increase of $724,895 or 42.8% for 2003, compared to 2002. The depletion rate is calculated using production as a percentage of reserves. This increase in depletion expense was mainly due to the increase in gas production during the year in 2003.

We also reevaluated our inventory of geological lease and land costs, which had been previously capitalized, in order to write off those prospects that may be no longer viable. As a result, $28,566 of previously capitalized costs were written off and recorded as geological and geophysical expense during 2002 compared with $209,622 written off in 2003, an $181,056 or 633.8% increase.

General and administrative expenses increased by $1,166,690, or 41.3%, to $3,993,668 for the year ended December 31, 2003 from $2,826,978 for the same period in 2002. We can attribute this increase to higher employee salaries and related expenses, due to increased staffing, management compensation, as well as increased travel costs. During 2003 we nearly doubled the size of our technical staff handling engineering and geologic activities. Legal and accounting expense decreased to $544,302 for the year, compared to $1,055,244 for 2002, a $510,942 (48.4%) decrease. The decrease can be attributed to lower litigation costs during the year in 2003, as we successfully concluded our only remaining material legal proceeding. See, Legal Proceedings, page 8. Marketing expense for the year ended December 31, 2003, increased $85,525 or 11.9%, to $804,366, compared to $718,841 for 2002. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs. In 2003 we were able to reduce our marketing expenses in proportion to total turnkey drilling revenue by relying mostly on internal marketing efforts of management, which does not result in payment of sales commissions, as opposed to sales through NASD firms acting as selling agents.

During the year in 2003, we increased borrowings under our commercial bank credit line, and interest expense increased to $194,997 for the year ended December 31, 2003 from $105,405 for the year in 2002, an $89,592 or 85.0% increase.

During the year in 2003, we utilized our remaining net operating loss carry-forwards for income tax purposes, and we began to accrue charges for current and deferred income tax expense. As a result, we incurred $2,217,005 in income tax expense during the year in 2003. In 2002, we had an income tax credit of $55,491 due to adjustments in previous year's taxes.

In 2003 we adopted SFAS 143 for Asset Retirement Obligations, which establishes accounting requirements for retirement obligations associated with tangible long-lived assets such as wells and production facilities. As a result, we recorded $41,301, net of tax, as a cumulative effect adjustment of a change in accounting principle.

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Capital Resources and Liquidity

At December 31, 2004, Royale Energy had current assets totaling $16,404,652 and current liabilities totaling $14,977,427, a $1,427,225 working capital surplus. We had cash and cash equivalents at December 31, 2004 of $7,627,045 compared to $4,877,618 at December 31, 2003.

Our capital expenditure commitments occur as we decide to drill wells to develop our prospects. We generally do not decide to drill any prospect until we have sold a portion of the working interest in a prospect to third parties to diversify our risk and receive a portion of the funds to drill each prospect. We place funds that we receive from third party investors into a separate cash account until they are required for expenditures on each well. Our capital expenditure needs in addition to those needs are satisfied by selling part of the working interest in prospects. We have not, in past years, experienced shortages of funds needed to satisfy our capital expenditure requirements. We expect that our available credit and cash flows from operations will be sufficient for capital expenditure needs beyond those satisfied from sales of working interests.

We ordinarily fund our operations and cash needs from cash flows generated from operations. During the fourth quarter of each year, we receive a large percentage of the revenue generated by our sales of working interests to third parties, as individual high net worth investors make investments according to their own year-end financial planning. We also incur a large percentage of our costs for drilling activities in the third and fourth quarters of each year. We believe that we have sufficient liquidity for the remainder of 2005 and do not foresee any liquidity demands that cannot be met from cash flow from operations.

At the end of 2004, our accounts receivable totaled $3,903,941 compared to $5,143,491 at December 31, 2003, a $1,239,550 (24.1%) decrease, mainly due to the $641,079 allowance for bad debts for receivables from direct working interest investors. At December 31, 2004, our accounts payable and accrued expenses totaled $9,628,066, an increase of $875,473 or 10.0% over the accounts payable at the end of 2003 of $8,752,593. This was primarily due to the accrual of drilling costs for six exploratory wells spudded during the fourth quarter of 2004.

Occasionally we borrow from banks, using our oil and gas properties as security. In 2003, we drew $890,000 from our credit line to meet our drilling schedule. During the year ended December 31, 2004, we drew approximately $1,082,500, net, from our credit line in order to purchase new oil and gas assets.

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, 2004, we had outstanding indebtedness of $5,472,500. At December 31, 2003, we had outstanding indebtedness under this agreement of $4,390,000. 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:

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-	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 current assets to 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.

Royale Energy was in compliance with all covenants under the credit line at March 1, 2005.

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. A portion of the real estate was subsequently sold during the year resulting in an approximately $390,000 principal payment. At December 31, 2004, we had outstanding indebtedness of $575,086 on this loan.

Operating Activities. For the year ended December 31, 2004, cash provided by operating activities totaled $8,018,300 compared to $9,885,100 provided by operating activities for the same period in 2003, a $1,866,800 or 18.9% decrease, mainly due to decreases in net revenues from operations.

Investing Activities. Net cash used by investing activities, primarily in capital acquisitions of oil and gas properties, amounted to $6,640,103 for the year in 2004, compared to $11,016,044 used by investing activities for the same period in 2003. This decrease in cash used was primarily due to fewer wells drilled, four developmental and ten exploratory in 2004 and 14 developmental and three exploratory in 2003.

Financing Activities. For the year ended December 31, 2004 cash provided by financing activities was $1,371,230 compared to $3,778,618 provided by financing activities for the same period in 2003. This difference in cash provided was primarily due to decreases in borrowings during 2004 when compared to 2003.

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 2004, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline. In 2004, our natural gas revenues were approximately $10.5 million with an average price of $5.43 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 $1 million. Due to our current production levels of oil and natural gas condensate, a 10% increase or decrease in our average price per barrel would not have a material impact on our financial statements. 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

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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 $90,000 to $140,000, respectively, to our interest expense.

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 2004 fiscal year. Based on their evaluation, they concluded that our disclosure controls are effective in providing reasonable assurance that material information relating to our company is made known to management on a timely basis during the period when our periodic reports are being prepared.

No changes in our internal control over financial reporting occurred during the last fiscal quarter of 2004 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.

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PART III

Item 10 Directors and Executive Officers of the Registrant

Listed below is certain information about Royale Energy's current directors and executive officers. Directors are elected by shareholders at each annual shareholders' meeting and serve until their successors are elected and qualified. Officers serve at the discretion of the board of directors.

Name	Age	First Became Director or Executive Officer	Positions Held
Harry E. Hosmer*	74	1986	Chairman of the Board
Donald H. Hosmer	50	1987	President, Secretary and Director
Stephen M. Hosmer	38	1996	Executive Vice President, Chief Financial Officer and Director
Oscar A. Hildebrandt*+	69	1995	Director
Rodney Nahama +	72	1994	Director
Gilbert Kemp +	70	1998	Director
George M. Watters*	84	1991	Director

* Member of the audit committee

+ Member of the compensation committee

A majority of the members of the board of directors may be considered independent directors under Nasdaq rules (including Messrs. Hildebrandt, Nahama, Kemp and Watters). The board of directors has determined that Dr. Oscar Hildebrandt and George Watters are "audit committee financial experts" as defined in Item 401 of Securities and Exchange Commission Regulation

S-B.

Following is a summary of the business experience of each director and executive officer for the past five years.

HARRY E. HOSMER is the Chairman of the Board of Royale Energy. He has served as Chairman since Royale Energy began in 1986, and from inception in 1986 until June 1995, he also served as President and Chief Executive Officer. Mr. Hosmer and his sons founded Royale Energy.

DONALD H. HOSMER is President, Chief Executive Officer, Secretary, and Director of Royale Energy. He has served as an executive officer and Director of Royale Energy since its inception in 1987, and in June 1995 he became President and Chief Executive Officer. Prior to becoming President, he was Executive Vice President, responsible for marketing working

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interests in oil and gas projects developed by Royale Energy. He was also responsible for investor relations and communications. Donald H. Hosmer is the son of Harry E. Hosmer and brother of Stephen M. Hosmer.

STEPHEN M. HOSMER is Executive Vice President, Chief Financial Officer and Director of Royale Energy. Mr. Hosmer joined Royale Energy as the Management Information Systems Manager in May 1988, responsible for developing and maintaining Royale Energy's computer software. Mr. Hosmer developed programs and software systems used by Royale Energy. From 1991 to 1995, he served as president of Royale Operating Company, Royale Energy's operating subsidiary. In 1995, he became Chief Financial Officer of Royale Energy. In 1996, he was elected to the board of directors of Royale Energy. Mr. Hosmer serves on the board of directors of Youth for Christ, a charitable organization in San Diego, California. Stephen M. Hosmer is the son of Harry E. Hosmer and brother of Donald H. Hosmer. He has a B.S. degree from Oral Roberts University in Business Administration and a Master of Business Administration from Pepperdine University.

OSCAR HILDEBRANDT, D.V.M., is a Director and is Chairman of Royale Energy's Compensation and Audit Committees. From 1994 to 1995 he served as an advisory member of Royale Energy's Board of Directors. Dr. Hildebrandt practiced veterinary medicine as President of Medford Veterinary Clinic, Medford, Wisconsin, from 1960 to 1990. Since 1990, Dr. Hildebrandt has engaged independently in veterinary practice consulting services. He has served on the board of directors of Fidelity National Bank - Medford, Wisconsin, and its predecessor bank from 1965 to the present and is past chairman of the board of the Bank. From 1990 to the present he has acted as a financial advisor engaged in private business interests. Dr. Hildebrandt received a Bachelor of Science degree from the University of Wisconsin in 1954 and a Doctor of Veterinary Medicine degree from the University of Minnesota in 1958.

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

RODNEY NAHAMA, a Director of Royale Energy, was employed as president and chief executive officer of Nahama & Weagant Energy Co. from 1971 until March 1994. Since March 1994, Mr. Nahama has pursued private business interests, including the provision of geologic consulting services to Royale Energy. Mr. Nahama holds a B.A. degree in geology from the University of California, Los Angeles, and an M.A. degree in geology from the University of Southern California. He was an independent exploration geologist from 1965 to 1971 and prior to that served as a geologist with Franco Western Oil Company from 1963 to 1965. Between 1957 and 1963, Mr. Nahama worked as an exploration geologist with

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Honolulu Oil Company, Getty Oil Company, and Sunray Oil Company. Mr. Nahama is a member of the American Association of Petroleum Geologists, the San Joaquin Geological Society, the California Independent Petroleum Association and the Independent Petroleum Association of America.

GEORGE M. WATTERS has been retired from full time employment during the last five years. Mr. Watters retired from AMOCO Corporation in 1983 after serving for 24 years in senior management positions with AMOCO Corporation and its affiliates. From 1987 to the present Mr. Watters has managed his personal investments. Mr. Watters received his B.S. degree from Massachusetts Institute of Technology in 1942.

Compliance with Section 16(a) of the Securities Exchange Act

Section 16(a) of the Securities Exchange Act of 1934 and Securities and Exchange Commission regulations require that Royale Energy's directors, certain officers, and greater than 10 percent shareholders file reports of ownership and changes in ownership with the SEC and the NASD and furnish Royale Energy with copies of all such reports they file. One director filed a late report on Form 4 during 2004. In June 2004, George M. Watters reported that he had sold 4,994 shares of our stock in May 2004.

Based solely upon a review of the copies of the forms furnished to Royale Energy, or representations from certain reporting persons that no reports were required, Royale Energy believes that no other persons failed to file required reports on a timely basis during or in respect of 2004.

Item 11 Executive Compensation

The following table summarizes the compensation of the chief executive officer and the other most highly compensated executive officers (the "named executive officers") of Royale Energy and its subsidiaries during the past year.

		Annual Compensation			Long Term Compensation
(a)	(b)	(c)	(d)	(e)	(i)
	Year	Salary	Bonus	Other Annual Compensation	All Other Compensation
Donald Hosmer	2004	$185,143	$ 85,000	$ 0	$5,726
President	2003	$173,113	$150,000	$ 0	$ 579
	2002	$156,125	$ 50,000	$2,110	$ 0

Stephen Hosmer	2004	$175,223	$ 85,000	$ 0	$5,419
Exec. V.P.	2003	$158,309	$150,000	$ 0	$5,340
& CFO	2002	$132,492	$ 50,000	$1,418	$5,340

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Other Annual Compensation: Under the terms of a plan adopted by the board of directors in 1989, each of the listed executives has elected to participate in wells drilled by Royale Energy. See, Certain Relationships and Related Transactions on page 26. The costs that they incurred for interests acquired in wells pursuant to this policy are less than would have been the cost of purchasing an equivalent percentage as working interests in these wells, which are sold to unaffiliated outside investors. Although the difference between the executives' actual cost and the cost incurred by outside investors possibly could be considered as additional compensation to them, Royale Energy's management does not believe that the amount of such difference should be treated as compensation. At any rate, management believes that the amount of the difference is insignificant. In addition, in 2002 and 2001, Royale Energy had advanced funds to the executives to pay for their well participation interests. After ad option of the Sarbanes-Oxley Act of 2002, the Company discontinued making such advances and required the directors to repay all outstanding amounts advanced. The Other Annual Compensation in the foregoing table consists of the amounts that the management believes may have been considered income to be imputed from such foregone interest. The imputed interest was estimated using approximate amounts due at the end of each period, as if that amount had been due for the entire period. Royale Energy used the imputed interest rate of 7% simple interest per annum.

All Other Compensation: Consists of Royale Energy's matching contribution to the company's simple IRA plan on behalf of the listed executives.

Royale Energy does not have employment agreements with any of its executives.

No Stock Options Were Granted in 2004

We did not grant any stock options, stock appreciation rights or Long-Term Incentive Plan Awards to our named executive officers during 2004.

Aggregate 2004 Option Exercises and Year End Values

The following table summarizes number and value of shares of stock options exercised by the named executive officers in 2004 and the number and value of all unexercised stock options held by those executive officers at the end of 2004.

	Shares acquired on exercise	Value realized	Number of securities underlying unexercised options/SARS at 12/31/04 exercisable/ unexercisable	Value of unexercised in- the-money options/SARS at 12/31/04 exercisable/ unexercisable
Donald H. Hosmer	11,078	$126,178	0/0	$0/0
Stephen M. Hosmer	-	-	19,615/0	$111,218/0

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The value of unexercised in-the-money options in the above table is based a stock price of $7.20 per share, which was our closing stock price on Nasdaq on December 31, 2004.

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 shareholder 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, 1999, 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, 2000 through December 31, 2004.

The Royale Energy performance figures assume retention of stock dividends in 2001, 2002, 2003 and 2004 and a stock split in 2004.

	1999	2000	2001	2002	2003	2004
Royale Energy, Inc.	100	290	293	268	725	571
S & P Composite 500 Stock Index	100	91	80	62	80	89
DJ US Exploration and Production Index	100	160	147	150	196	279

Compensation of Directors

Each director who is not an employee of Royale Energy receives a quarterly fee for his services, which in 2004 was set at $3,025. In addition, Royale Energy reimburses directors for the expenses they incur for their service. No directors received any stock options or stock appreciation rights in 2004.

Item 12 Security Ownership of Certain Beneficial Owners and Management

The following tables set forth certain information regarding the ownership of Royale Energy's voting securities as of December 31, 2004, by: (i) each person Royale Energy knows to own beneficially more than 5% of the outstanding shares of each class of equity securities, (ii) each of Royale Energy's directors, and (iii) all of Royale Energy's directors and officers as a group. Except pursuant to applicable community property laws and except as otherwise indicated, each shareholder identified in the table possesses sole voting and investment power with respect to its or his shares.

Common Stock

On December 31, 2004, 7,839,223 shares of our common stock were outstanding. The

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following table sets forth share ownership information for our officers, directors, and holders of more than 5% of our equity securities as of December 31, 2004.

Shareholder (2)	Number (1)	Percent

Donald H. Hosmer (3)	1,018,486	12.99%

Harry E. Hosmer (3)	778,797	9.93%

Oscar A. Hildebrandt	75,735	Less than 1%

Stephen M. Hosmer (3)	1,242,122	15.81%

Gilbert C. L. Kemp	16,962	Less than 1%

Rodney Nahama	27,459	Less than 1%

George M. Watters	58,841	Less than 1%

All officers and directors as a group	3,218,402	40.31%

(1) Includes shares which the listed shareholder has the right to acquire before March 1, 2005, from options or warrants, as follows: Stephen M. Hosmer 19,614, Oscar Hildebrandt 39,227, Rodney Nahama 27,459, George M. Watters 58,841, and all officers and directors as a group 145,141.

(2) The mailing address of each listed shareholder is 7676 Hazard Center Drive, Suite 1500, San Diego, California 92108.

(3) Donald H. Hosmer and Stephen M. Hosmer are sons of Harry E. Hosmer, Chairman of the Board.

Preferred Stock

Holders of each series of Convertible Preferred Stock have voting rights equal to the number of shares into which they are convertible. On December 31, 2004, there were 6,122 shares of Series A and 57,416 shares of Series AA Convertible Preferred Stock outstanding. The shares of each series of Preferred shares are convertible into shares of Royale Energy's Common Stock at the option of the security holder, at the rate of two shares of Convertible Preferred Stock for each share of Common Stock. The Preferred Stock is not registered under the Securities Exchange Act of 1934, and no market exists for the Preferred Stock. The total number of shares of Common Stock issuable on conversion of all outstanding shares of Preferred Stock equals less than 1% of the outstanding Common Stock of Royale Energy. To Royale Energy's knowledge,

-25-

none of the Preferred shareholders would own more than 1% of Royale Energy's Common Stock, if their Preferred shares were converted to Common shares.

Item 12 Certain Relationships and Related Transactions

In 1989, the board of directors adopted a policy (the "1989 policy") that permits each director and officer of Royale Energy to purchase from Royale Energy, at its cost, up to one percent (1%) fractional interest in any well to be drilled by Royale Energy. When an officer or director elects to make such a purchase, the amount charged per each percentage working interest is equal to Royale Energy's actual pro rata cost of drilling and completion, rather than the higher amount that Royale Energy charges to working interest holders for the purchase of a percentage working interest in a well. Of the current officers and directors, Donald Hosmer, Stephen Hosmer, Harry E. Hosmer, George Watters and Oscar Hildebrandt at various times have elected under the 1989 policy to purchase interests in certain wells Royale Energy has drilled.

Under the 1989 policy, officers and directors may elect to participate in wells at any time up until drilling of the prospect begins. Participants are required to pay all direct costs and expenses through completion of a well, whether or not the well drilling and completion expenses exceed Royale Energy's cost estimates, instead of paying a set, turnkey price (as do outside investors who purchase undivided working interests from Royale Energy). Thus, they participate on terms similar to other oil and gas industry participants or joint venturers. Participants are invoiced in advance for their share of estimated direct costs of drilling and completion and later actual costs are reconciled, as Royale Energy incurs expenses and participants make further payments as necessary.

Officer and director participants under this program do not pay some expenses paid by outside, retail investors in working interests, such as sales commissions, if any, or marketing expenses. The outside, turnkey drilling agreement investors, on the other hand, are not obligated to pay additional costs if a drilling project experiences cost overruns or unanticipated expenses in the

drilling and completion stage. Accordingly, Royale Energy's management believes that its officers and directors who participate in wells under the Board of Directors' policy do so on terms the same as could be obtained by unaffiliated oil and gas industry participants in arms-length transactions, albeit those terms are different than the turnkey agreement under which outside investors purchase fractional undivided working interests from Royale Energy.

Donald and Stephen Hosmer each have participated individually in 114 wells under the 1989 policy. The Hosmer Trust, a trust for the benefit of family members of Harry E. Hosmer, has participated in 113 wells.

Donald Hosmer's 2004 investments in wells under the 1989 policy totaled $137,716 in fractional interests in 14 wells. In 2004, Stephen Hosmer purchased fractional interests in 14 wells under the 1989 policy, for a total investment of $132,878. The Hosmer Trust purchased fractional interests in 14 wells during 2004 for a total investment of $138,492.

-26-

Current officers and directors were billed $196,323 and $305,489 for their interests for the years ended December 31, 2004 and 2003, respectively. Under the Sarbanes-Oxley Act of 2002, these amounts can no longer be billed to officers and directors. Instead, these amounts are either collected in advance or offset against compensation due.

Royale Energy's Chairman of the Board and former President, Harry E. Hosmer, renders management consulting services to Royale Energy on an ongoing basis. Royale Energy compensated Mr. Hosmer $138,600 for his consulting services in 2004 and pays his medical insurance costs. Mr. Hosmer's consulting services are in conjunction with his service on the board of directors, for which he receives reimbursement of expenses to attend meetings.

Item 13 Exhibits

(a)		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.
4.1		Certificate of Determination of the Series A Convertible Preferred Stock, incorporated by reference to Exhibit 4.1 of Royale Energy's Form 10-SB Registration Statement.
4.2		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.

Item 14 Principal Accountant Fees and Services

The following table sets forth the aggregate fees billed by our previous independent accountants, Brown Armstrong Paulden McCown Starbuck & Keeter Accountancy Corporation, for the years ended December 31, 2003 and 2002.

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	2004	2003
Audit fees ⁽¹⁾	$ 53,214	$ 69,394
Audit-related fees ⁽²⁾	22,292	12,796
Tax fees ⁽³⁾	7,577	27,601
All other fees ⁽⁴⁾	10,372	14,501
Total	$ 93,455	$124,292

During 2004 Sprouse & Anderson, LLP became our new independent accountants. The aggregate fees billed by them for the years ended December 31, 2004 and 2003 are as follows:

	2004	2003
Audit fees ⁽¹⁾	$ 20,867	$ -
Audit-related fees ⁽²⁾	-	-
Tax fees ⁽³⁾	-	-
All other fees ⁽⁴⁾	-	-
Total	$ 20,867	$ -

(1) Audit fees are fees for professional services rendered for the audit of Royale Energy's annual financial statements, reviews of financial statements included in the company's Forms 10-Q, and reviews of documents filed with the U.S. Securities and Exchange Commission.

(2) Audit related fees consist of fees for services reasonably related to performance of the audit or review of Royale Energy's financial statements. For 2004 and 2003, these services include quarterly reviews of financial information.

(3) Tax fees consist of tax planning, consulting and tax return reviews.

(4) Other fees consist of work on registration statements under the Securities Act of 1933.

The audit committee of Royale Energy has adopted policies for the pre-approval of all audit and non-audit services provided by the company's independent auditor. The policy requires pre-approval by the audit committee of specifically defined audit and non-audit services. Unless the specific service has been previously pre-approved with respect to that year, the audit committee must approve the permitted service before the independent auditor is engaged to perform it.

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.

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		ROYALE ENERGY, INC.

Date: April 14, 2005		/s/ Donald H. Hosmer
		Donald H. Hosmer, President and Chief Executive Officer

Date: April 14, 2005		/s/ Stephen M. Hosmer
		Stephen M. Hosmer, Executive Vice President and Chief Financial Officer (Chief Accounting Officer)

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

Date: April 14, 2005		/s/ Harry E. Hosmer
		Harry E. Hosmer
		Chairman of the Board of Directors

Date: April 14, 2005		/s/ Donald H. Hosmer
		Donald H. Hosmer
		Director, President and Chief Executive Officer

Date: April 14, 2005		/s/ Stephen M. Hosmer
		Stephen M. Hosmer
		Director and Executive Vice President and Chief Financial Officer

Date: April 14, 2005		/s/ Oscar A. Hildebrandt
		Oscar A. Hildebrandt
		Director

Date: April 14, 2005		/s/ Rodney Nahama
		Rodney Nahama
		Director

Date:
		Gilbert C. L. Kemp
		Director

Date:
		George M. Watters
		Director

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ROYALE ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA

Index to Financial Statements	F-1

Report of Sprouse & Anderson, LLP, Independent Auditors	F-2

Report of Brown Armstrong Paulden McCown Starbuck & Keeter	F-3

Balance Sheets at December 31, 2004 and 2003	F-4

Statements of Income for the Years Ended December 31, 2004, 2003 and 2002	F-6

Statements of Stockholders' Equity for the Years Ended December 31, 2004, 2003 and 2002	F-7

Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002	F-10

Notes to the Financial Statements	F-11

Supplemental Information About Oil and Gas Producing Activities (Unaudited)	F-29

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.

F-1

INDEPENDENT AUDITORS' REPORT

The Board of Directors

Royale Energy, Inc.:

We have audited the accompanying balance sheet of Royale Energy, Inc. (a California corporation) as of December 31, 2004, and the related statements of operations, stockholders' equity and cash flows for the year ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with standards of the Public Company Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company has determined that it is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Royale Energy, Inc. as of December 31, 2004, and the results of its operations and its cash flows for the year ended December 31, 2004 in conformity with U.S. generally accepted accounting principles.

SPROUSE & ANDERSON, L.L.P.

February 18, 2005

F-2

REPORT OF INDEPENDENT AUDITOR

Shareholders and Board of Directors

Royale Energy, Inc.

We have audited the accompanying balance sheets of Royale Energy, Inc. (a California corporation) as of December 31, 2003 and 2002, and the related statements of operations, stockholders' equity and cash flows for the years then ended. These financial statements are the responsibility of Royale Energy's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audits in accordance with auditing standards generally accepted in the Untied States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly in all material respects, the financial position of Royale Energy, Inc., as of December 31, 2003 and 2002, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.

BROWN ARMSTRONG PAULDEN

McCOWN STARBUCK & KEETER

ACCOUNTANCY CORPORATION

Bakersfield, California

February 13, 2004

F-3

BALANCE SHEETS

DECEMBER 31, 2004 AND 2003

ASSETS

	2004	2003

Current Assets
Cash and Cash Equivalents	$ 7,627,045	$ 4,877,618
Accounts Receivable	3,903,941	5,143,491
Prepaids	3,570,850	1,329,508
Deferred Tax Asset	1,155,338	1,005,952
Inventory	147,478	128,223

Total Current Assets	16,404,652	12,484,792

Investments	6,946	281,946

Oil and Gas Properties (successful efforts basis),
Equipment and Fixtures	26,137,071	22,903,766

Total Assets	$ 42,548,669	$ 35,670,504

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

F-4

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities
Accounts Payable and Accrued Expenses	$ 9,628,066	$ 8,752,593
Current Portion of Long-Term Debt	69,944	-
Deferred Revenue from Turnkey Drilling	5,279,417	4,034,881

Total Current Liabilities	14,977,427	12,787,474

Noncurrent Liabilities
Asset Retirement Obligation	266,462	195,712
Deferred Tax Liability	4,138,317	3,028,030
Long-Term Debt, Net of Current Portion	5,977,642	4,390,000

Total Noncurrent Liabilities	10,382,421	7,613,742

Total Liabilities	25,359,848	20,401,216

Redeemable Preferred Stock
Series A, Convertible Preferred Stock, No Par Value,
259,250 Shared Authorized; 6,122 and 4,611 Shares
Issued and Outstanding.	11,589	11,172

Stockholders' Equity
Common Stock, No Par Value, 10,000,000 Shares
authorized; 7,859,223 and 5,641,829 issued
and 7,839,223 and 5,621,829 outstanding.	19,591,039	19,108,978
Convertible Preferred Stock, Series AA, No Par Value,
147,500 Shares Authorized; 57,416 and 43,240
Shares Issued and Outstanding	167,979	163,926
Accumulated (Deficit)	(2,500,641)	(4,693,393)

Total Paid in Capital and Accumulated Deficit	17,258,377	14,579,511

Less Cost of Treasury Stock, 20,000 and 20,000 Shares	(97,906)	(97,906)
Paid in Capital, Treasury Stock	16,761	16,761
Dividend to be Distributed	0	759,750

Total Stockholders' Equity	17,188,821	15,269,288

Total Liabilities and Stockholders' Equity	$ 42,548,669	$ 35,670,504

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

F-5

ROYALE ENERGY, INC.

STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002

	2004	2003	2002
Revenues
Sale of Oil and Gas	$ 10,892,574	$ 10,120,148	$ 4,930,278
Turnkey Drilling	13,269,996	11,966,860	6,890,431
Supervisory Fees and Other	1,781,786	1,178,129	619,179

Total Revenues	25,944,356	23,265,137	12,439,888

Costs and Expenses
General and Administrative	5,205,190	3,993,668	2,826,978
Geological and Geophysical Expenses	321,983	209,622	28,566
Turnkey Drilling Development	8,150,338	5,855,661	4,156,239
Lease Operating	2,817,448	1,714,382	1,450,893
Lease Impairment	51,414	869,991	596,222
Legal and Accounting	627,038	544,302	1,055,244
Marketing	1,284,809	804,366	718,841
Depreciation, Depletion and Amortization	3,714,271	2,418,922	1,694,027

Total Costs and Expenses	22,172,491	16,410,914	12,527,010

Income (Loss) from Operations	3,771,865	6,854,223	(87,122)

Other Expenses
Interest Expense	273,050	194,997	105,405

Income (Loss) Before Income Tax Expense	3,498,815	6,659,226	(192,527)

Income Tax Expense (Benefit)	1,306,063	2,217,005	(55,491)

Net Income Before Cumulative Effect
of Accounting Change	2,192,752	4,442,221	(137,036)

Cumulative Effect of Accounting Change	-	(41,301)	-

Net Income (Loss)	$ 2,192,752	$ 4,400,920	$ (137,036)

Basic Earnings Per Share:
Net income (loss) available to common stock	$ 0.32	$ 0.71	$ (0.02)
Cumulative effect of accounting change	$ -	$ -	$ -

Diluted Earnings (Loss) Per Share	$ 0.31	$ 0.65	$ (0.02)

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

F-6

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002

	Common Stock		Preferred Stock Series AA
	Shares		Shares
	Outstanding	Amount	Outstanding	Amount
Balance at January 1, 2002	4,373,045	$12,198,711	43,127	$ 173,181

15% Stock Dividend	652,959	4,472,769	6,466	22,146

Conversion of Preferred A
to Common Stock	3,594	17,101	-	-

Conversion of Preferred AA
to Common Stock	503	3,514	(1,012)	(3,514)

Stock Awards Granted from Treasury	-	-	-	-

Net Income (Loss) for the Year	-	-	-	-

Balance at December 31, 2002	5,030,101	16,692,095	48,581	191,813

15% Stock Dividend	585,924	2,709,205	5,261	12,735

Conversion of Preferred A
to Common Stock	503	2,180	-	-

Conversion of Preferred AA
to Common Stock	5,301	40,622	(10,602)	(40,622)

Stock Awards Granted from Treasury	-	-	-	-

Stock Options Repurchase	-	(335,124)	-	-

Net Income (Loss) for the Year	-	-	-	-

Balance at December 31, 2003	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 Reorg.	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

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

F-7

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002

	Preferred Stock Series A
	Shares		Accumulated
	Outstanding	Amount	Deficit

Balance at January 1, 2002	10,781	$24,066	$(1,001,483)

15% Stock Dividend	1,475	5,052	(4,472,769)

Conversion of Preferred A
to Common Stock	(7,188)	(17,101)	-

Conversion of Preferred AA
to Common Stock	-	-	-

Stock Awards Granted from Treasury	-	-	-

Net Income (Loss) for the Year	-	-	(137,036)

Balance at December 31, 2002	5,068	12,017	(5,611,288)

15% Stock Dividend	551	1,335	(3,468,955)

Conversion of Preferred A
to Common Stock	(1,008)	(2,180)	(1,335)

Conversion of Preferred AA
to Common Stock	-	-	(12,735)

Stock Awards Granted from Treasury	-	-	-

Stock Options Repurchase	-	-	-

Net Income (Loss) for the Year	-	-	4,400,920

Balance at December 31, 2003	4,611	$ 11,172	$(4,693,393)

3.75% Stock Dividend	172	417	-

28% Stock Dividend	1,339	-	-

Net Income (Loss) for the Year	-	-	2,192,752

Balance at December 31, 2004	6,122	$ 11,589	$(2,500,641)

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

F-8

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002

	Treasury Stock
	Shares		Paid in Capital	Dividend to be
	Outstanding	Amount	Treasury Stock	Distributed	Total

Balance at January 1, 2002	26,000	$ (127,306)	$ -		$11,267,169

15% Stock Dividend	-	-	-	-	27,198

Conversion of Preferred A
to Common Stock	-	-	-	-	-

Conversion of Preferred AA
to Common Stock	-	-	-	-	-

Stock Awards Granted from Treasury	(6,000)	29,400	16,761	-	46,161

Net Income (Loss) for the Year	-	-	-	-	(137,036)

Balance at December 31, 2002	20,000	(97,906)	16,761	-	11,203,492

15% Stock Dividend	-	-	-	759,750	14,070

Conversion of Preferred A
to Common Stock	-	-	-	-	(1,335)

Conversion of Preferred AA
to Common Stock	-	-	-	-	(12,735)

Stock Awards Granted from Treasury	-	-	-	-	-

Stock Options Repurchase	-	-	-	-	(335,124)

Net Income (Loss) for the Year	-	-	-	-	4,400,920

Balance at December 31, 2003	20,000	$(97,906)	$16,761	$759,750	$15,269,288

3.75% Stock Dividend Distributed	-	-	-	(759,750)	-

Royale Petroleum Corp. - Stock Reorg.	-	-	-	-	-

Acquisition of Royale Petroleum Corp.	-	-	-	-	5,377

Stock Options Repurchased	-	-	-	-	(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

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

F-9

ROYALE ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

	2004	2003	2002

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ 2,192,752	$ 4,400,920	$ (137,036)
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation, Depletion, and Amortization	3,714,271	2,418,922	1,694,028
Compensation Expense - Stock Grants	-	-	46,161
Lease Impairment	51,414	869,991	596,222
Bad Debt Expense	641,079	-	-
(Increase) Decrease in:
Accounts Receivable	598,471	(1,407,255)	(211,198)
Prepaid Expenses and Other Assets	(2,409,983)	(587,717)	(1,462,451)
Increase (Decrease) in:
Accounts Payable and Accrued Expenses	875,473	2,721,546	2,488,045
Deferred Revenues - DWI	1,244,536	1,468,693	(174,803)
Deferred Income Taxes	1,110,287	-	-

Net Cash Provided by Operating Activities	8,018,300	9,885,100	2,838,968

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Oil and Gas Properties And other capital expenditures	(6,915,103)	(11,016,044)	(5,240,883)
Proceeds from Sale of Investments	275,000	-	-

Net Cash Used in Investing Activities	(6,640,103)	(11,016,044)	(5,240,883)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt (Net)	1,657,586	4,113,742	1,500,000
Repurchase of Stock Options	(286,356)	(335,124)	-

Net Cash Provided by Financing Activities	1,371,230	3,778,618	1,500,000

Net Increase (Decrease) in Cash and Cash Equivalents	2,749,427	2,647,674	(901,915)

Cash at Beginning of Year	4,877,618	2,229,944	3,131,859

Cash at End of Year	$ 7,627,045	$ 4,877,618	$ 2,229,944

SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:


Cash Paid for Interest	$ 211,633	$ 194,997	$ 105,405

Cash Paid for Taxes	$ 601,523	$ 12,670	$ -

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

F-10

ROYALE ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This summary of significant accounting policies of Royale Energy, Inc. ("Royale Energy") is presented to assist in understanding Royale Energy's financial statements. The financial statements and notes are representations of Royale Energy's management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.

Description of Business

Royale Energy is an independent oil and gas producer which also has operations in the area of turnkey drilling. Royale Energy owns wells and leases in major geological basins located primarily in California, Texas, and Utah. Royale Energy offers fractional working interests and seeks to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing.

Use of Estimates

Material estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proven reserves. Estimated reserves are used in the calculation of depletion, depreciation and amortization, unevaluated property costs, estimated future net cash flows, taxes, and contingencies.

Joint Ventures

The accompanying financial statements as of December 31, 2004 and 2003 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 gas in the period of delivery.

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

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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 the well is spudded (begun). Drilling is generally completed within 7-14 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 p roperties are computed on an aggregate basis using the units-of-production method.

Financial Accounting Standards Board (FASB), Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets ", requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. It establishes guidelines for determining recoverability based on future net cash flows from the use of the asset and for the measurement of the impairment loss. Impairment loss under SFAS No. 144 is calculated as the difference between the carrying amount of the asset and its fair value. Any impairment loss is recorded in the current period in which the recognition criteria are first applied and met. Under the successful efforts method of accounting for oil and gas operations, Royale Energy periodically assessed its proved properties for impairments by comparing the aggregate net book carrying amount of all proved properties with their aggregate future net cash flows. The statement requires that the impairment review be performed on the lowest level of asset groupings for which there are identifiable cash flows.

Royale Energy performs a periodic review for impairment of proved properties on a field-by-field basis. Unamortized capital costs are measured on a field basis and are reduced to fair value if it is determined that the sum of expected future net cash flows are less than the net book value. Royale Energy determines if an 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 $51,414 and $869,991 were recorded in 2004 and 2003, respectively.

Upon the sale of oil and gas reserves in place, costs less accumulated amortization of such property are removed from the accounts and resulting gain or loss on sale is reflected in operations. Impairment of unproved properties is assessed periodically on a property-by-property basis, and any impairment in value is currently charged to expense. In addition, capitalized costs of unproved properties are assessed periodically to determine whether their value has been impaired below the capitalized costs. Loss is recognized to the extent that such impairment is indicated. In making these assessments, factors such as exploratory drilling results, future drilling plans, and lease expiration terms are considered. When an entire interest in an unproved property is sold, gain or loss is recognized, taking into consideration any

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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.

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 is valued at the lower of cost or market as determined by the first-in, first-out method.

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, 2004, the accounts receivable balance was $3,903,941 and at December 31, 2003 it was $5,143,491. During 2004, the Company established an allowance for bad debts of $641,079 for receivables from direct working interest investors whose expenses on non-producing wells was unlikely to be collected.

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, 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

Cumulative effect of accounting change	-	-	-

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

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	For the Year Ended December 31, 2003
	Income	Shares	Per-Share
	(Numerator)	(Denominator)	Amount

Basic Earnings Per Share:
Net income available to common stock	$ 4,442,221	6,184,842	$ 0.72

Cumulative effect of accounting change	(41,301)	-	-

Diluted Earnings Per Share:
Effect of dilutive securities and stock options	-	550,410	(0.07)

Net income available to common stock	$ 4,400,920	6,735,252	$ 0.65

	For the Year Ended December 31, 2002
	Income	Shares	Per-Share
	(Numerator)	(Denominator)	Amount

Basic Earnings Per Share:
Net income available to common stock	$ (137,036)	6,152,869	$ (0.02)

Diluted Earnings Per Share:
Effect of dilutive securities and stock options	-	274,693	-

Net income available to common stock	$ (137,036)	6,425,562	$ (0.02)

Stock Based Compensation

Royale Energy has a stock-based employee and director compensation plan, which is more fully described in Note 13. Royale Energy accounts for this plan under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations. No stock-based compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

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:

	2004	2003	2002
Net income (loss), as reported	$ 2,192,752	$ 4,400,920	$ (137,036)

Add: Stock-based employee compensation
expense included in reported net income, net
of related tax effects.	-	-	-

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	2004	2003	2002

Deduct: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects	-	(137,318)	(56,991)

Pro forma net income	$ 2,192,752	$ 4,263,602	$ (194,027)

Earnings per share:
Basic -- as reported	$ 0.32	$ 0.85	$ (0.03)
Basic -- pro forma	$ 0.32	$ 0.82	$ (0.04)

Diluted -- as reported	$ 0.31	$ 0.79	$ (0.03)
Diluted -- pro forma	$ 0.31	$ 0.76	$ (0.04)

In December 2002, the Financial Accounting Standards Board issued SFAS No. 148, Accounting for Stock-Based Compensation, an Amendment of SFAS No. 123 ("SFAS 123") in an effort to encourage the recognition of compensation expense for the issuance of stock options. Royale Energy has elected to continue accounting for stock-based compensation under APB Opinion No. 25 and disclose pro forma net income and earnings per share, as if the fair value based method of accounting defined in Statement 123 and 148 had been applied.

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.

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.

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Recently Issued Accounting Pronouncements

In August 2001, the FASB approved SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 replaces SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The new accounting model for long-lived assets to be disposed of by sale applies to all long-lived assets, including discontinued operations, and replaces the provisions of APB Opinion No. 30, "Reporting Results of Operations-Reporting the Effects of Disposal of a Segment of a Business", for the disposal of segments of a business. SFAS 144 requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operatio ns to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of SFAS 144 are effective for financial statements issued for fiscal years beginning after December 15, 2001 and therefore were adopted by the Company in 2002. The adoption of this statement did not impact the Company's financial position, results of operations, or cash flows.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections". SFAS 145, which is effective for fiscal years beginning after May 15, 2002, provides guidance for income statement classification of gains and losses on extinguishment of debt and accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. The adoption of this statement did not impact the Company's financial position, results of operations, or cash flows.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 nullifies the guidance of the Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS 146 requires that a liability for a cost that is associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that fair value is the objective for the initial measurement of the liability. The provisions of SFAS 146 are required for exit or disposal activities that are initiated after December 31, 2002. The adoption of this statement did not impact the Company's financial position, results of operations, or cash flows.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." SFAS 148 amends FASB Statement No. 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. The adoption of this statement did not impact the Company's financial position, results of operations, or cash flows.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." This statement requires the consolidation of certain entities that are determined to be variable interest entities. An entity is determined to be a variable interest entity when either (I) the entity lacks sufficient equity to carry on its principal operations, (II) the equity owners of the entity cannot make decisions about the entity's activities or (III) the entity's equity neither absorbs losses or benefits from gains. The Company has reviewed its financial arrangements and has not identified any material variable interest entities that should be consolidated by the Company in accordance with FASB Interpretation No. 46.

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments

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and Hedging Activities." SFAS 149 amends SFAS No.133, "Accounting for Derivative Instruments and hedging Activities." SFAS 149 requires that contracts with comparable characteristics be accounted for similarly. In addition, SFAS 149 also clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative and clarifies when a derivative contains a financing component. This statement became effective for contracts entered into or modified after June 30, 2003. The adoption of this statement did not impact the Company's financial position, results of operations, or cash flows.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS 150 will result in a more complete depiction of an entity's liabilities and equity and will, therefore, assist investors and creditors in assessing the amount, timing, and likelihood of potential future cash outflows and equity share issuances. Furthermore, SFAS 150 will enhance the relevance of accounting information by providing more information about an entity's obligations to transfer assets or issue shares, therefore, improving its predictive value to users. SFAS 150 requires that certain obligations that could be settled by issuance of an entity's equity but lack other characteristics of equity be reported as liabilities even though the obligation does not meet the definition of liabilities as stated in Concepts Statement 6. This statement became effective for financial instruments entered into or modified after May 31, 2003, an d otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this statement did not impact the Company's financial position, results of operations, or cash flows.

In December of 2004, the FASB amended SFAS No. 123, "Accounting for Stock-Based Compensation." For equity instruments awarded to employees in exchange for service, companies are required to measure the cost of the employees' service based on fair value and recognize these costs over the vesting period of the equity instrument. This statement eliminates the option in Opinion 25 to use the intrinsic value method of measuring the cost of the employees' service. This statement is effective for non-small business issuers for reporting periods beginning after June 15, 2005 and for small business issuers for fiscal periods beginning after December 15, 2005. We do not expect this statement to materially affect the Company's financial position, results of operations, or cash flows.

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.

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Reclassification

Certain amounts in the financial statements have been reclassified to be consistent and comparable from year-to-year.

NOTE 2 - INVESTMENTS

At December 31, 2003, the Company owned 27,500 shares of C&K Capital Corporation Series A preferred stock. This investment did not have a readily determinable market price and was carried at cost. During 2004 this investment was redeemed at full face value of $275,000 along with interest due.

NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

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

	2004	2003
Oil and Gas

Producing properties, including intangible drilling costs	$ 24,268,397	$ 18,112,289
Undeveloped properties	2,082,853	3,377,875
Lease and well equipment	8,041,522	6,753,535

	34,392,772	28,243,699
Accumulated depletion, depreciation and amortization	(10,897,900)	(7,577,027)

	23,494,872	20,666,672

Commercial and Other

Real estate, including furniture and fixtures	1,005,916	1,406,469
Vehicles	225,523	138,571
Furniture and equipment	2,142,871	1,249,787

	3,404,310	2,794,827
Accumulated depreciation	(762,111)	(557,733)

	2,642,199	2,237,094

	$ 26,137,071	$ 22,903,766

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

	2004	2003	2002

Acquisition	$ 3,217,409	$ 3,058,667	$ 824,537
Development	$ 2,388,723	$ 4,396,398	$ 2,484,994
Exploration	$ 9,831,881	$ 3,053,823	$ 4,359,792

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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 two years ended December 31, are as follows:

	2004	2003	2002

Oil and gas sales	$ 10,892,574	$ 10,120,148	$ 4,930,278
Production related costs	(2,817,448)	(1,714,382)	(1,450,893)
Geological and geophysical expense	(321,983)	(209,622)	(28,566)
Depreciation, depletion and amortization	(3,714,271)	(2,418,922)	(1,694,027)

Results of operations from producing and
exploration activities	$ 4,038,872	$ 5,777,222	$ 1,756,792

NOTE 4 - 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.

The company adopted SFAS 143 as of January 1, 2003. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $157,185 increase in the carrying values of proved properties and a $188,007 increase in noncurrent abandonment liabilities. The net impact of these items was to record $41,301, net of tax, as a cumulative effect adjustment of a change in accounting principle in our Statement of Income for 2004. The asset obligation relates to costs to plug and abandon oil and gas properties of the Company.

	2004	2003
Asset retirement obligation
Beginning of the year	$(195,712)	$(188,007)
Liabilities incurred during the period	(73,804)	-
Settlements	31,694	-
Accretion expense	(64,113)	(7,705)
Revisions in estimated cash flow	35,473	-
Asset retirement obligation
End of year	$(266,462)	$(195,712)

The following pro-forma financial information summarizes the impact of Statement 143 on 2002 financial information as if the statement had been applied retroactively to January 1, 2002:

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	December 31, 2002
	As reported	Pro-forma
Operating loss	$ (87,122)	$ (128,423)
Net Income	(137,036)	(178,337)
Loss per common share - basic	(0.02)	(0.03)
Loss per common share - diluted	(0.02)	(0.03)

NOTE 5 - 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, 2004 and 2003, Royale Energy had recorded deferred turnkey drilling revenue associated with undrilled wells of $5,279,417 and $4,034,881, respectively, as a current liability.

NOTE 6 - 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 2004 and 2003:

	Oil and Gas
	Producing	Turnkey
	and	Drilling
	Exploration	Services	Total
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	$ 653,031	$ 653,032	$ 1,306,063

Total Assets	$ 42,548,669	$ -	$ 42,548,669

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	Oil and Gas Producing And Exploration	Turnkey Drilling Services	Total

Net Income	$ 1,718,987	$ 473,765	$ 2,192,752

Year Ended December 31, 2003
Revenues from External Customers	$ 10,120,148	$ 11,966,860	$ 22,087,008

Supervisory Fees	$ 1,134,116	$ -	$ 1,134,116

Interest Revenue	$ 44,013	$ -	$ 44,013

Interest Expense	$ 97,499	$ 97,498	$ 194,997

Expenditures for Segment Assets	$ 4,801,248	$ 8,320,753	$ 13,122,001

Depreciation, Depletion, and Amortization	$ 2,306,200	$ 112,722	$ 2,418,922

Lease Impairment	$ 434,996	$ 434,995	$ 869,991

Income Tax (Benefit)	$ 1,108,503	$ 1,108,502	$ 2,217,005

Cumulative Effect of Accounting Change	$ (20,651)	$ (20,650)	$ (41,301)

Total Assets	$ 35,670,504	$ -	$ 35,670,504

Net Income (Loss)	$ 2,529,180	$ 1,871,740	$ 4,400,920

Year Ended December 31, 2002

Revenues from External Customers	$ 4,930,278	$ 6,890,431	$ 11,820,709

Supervisory Fees	$ 583,637	$ -	$ 583,637

Interest Revenue	$ 35,543	$ -	$ 35,543

Interest Expense	$ 52,703	$ 52,702	$ 105,405

Expenditures for Segment Assets	$ 3,769,970	$ 6,466,791	$ 10,236,761

Depreciation, Depletion, and Amortization	$ 1,615,130	$ 78,897	$ 1,694,027

Lease Impairment	$ 298,111	$ 298,111	$ 596,222

Income Tax (Benefit)	$ (27,745)	$ (27,746)	$ (55,491)

Total Assets	$ 23,300,727	$ -	$ 23,300,727

Net Income (Loss)	$ (158,711)	$ 21,675	$ (137,036)

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NOTE 7 - LONG-TERM DEBT

	2004	2003
Revolving line of credit secured by oil and gas properties, with a maximum available of $5,750,000 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 6.0% at December 31, 2004, payable monthly with borrowing base reductions of $125,000 commencing on February 1, 2003. All unpaid principal and interest is payable at maturity on January 21, 2006.	$ 5,472,500	$ 4,390,000

Term Note (Secured by Deed of Trust), dated March 17, 2004, in the original principal amount of $1,0000,000, 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.	$ 575,086	$ -

Total Long Term Debt	$ 6,047,586	$ 4,390,000

Less Current Maturity	$ (69,944)	$ -

Long Term Debt Less Current Portion	$ 5,977,642	$ 4,390,000

Under the terms of the agreement, the Company is required to have a positive net worth not less than $8,188,000 as of September 30, 2002, plus 50% of positive quarterly net income thereafter, debt service coverage not less than 1.25:1, current ratio not less than 1:1, debt and lien restrictions, and dividend and distribution restrictions. The Company was in compliance with the terms of this agreement at December 31, 2004.

Maturities of long-term debt for years subsequent to December 31, 2004 are as follows:

Year Ended
December 31,

2005		$ 69,944
2006		$ 5,547,500
2007		$ 430,142
		$ 6,047,586

NOTE 8 - 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, 2004 and 2003, respectively, are as follows:

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	2004	2003	2002
Deferred Tax Assets:
Statutory Depletion Carry Forward	$ 816,270	$ 984,595	$ 342,000
Capital Loss / AMT Credit Carry Forward	133,023	21,357	-
Allowance for Doubtful Accounts	206,045	-	-

	1,155,338	1,005,952	342,000

Deferred Tax Liabilities:
Oil and Gas Properties and Fixed Assets	4,138,317	3,028,030	-

Net Deferred Tax Liability	$ 2,982,979	$ 2,022,078	$ -

The Company had statutory percentage depletion carry forwards of approximately $2,366,000 and $2,885,000 at December 31, 2004 and 2003 respectively. The depletion has no expiration date. The Company also has a capital loss carryforward of approximately $41,000 and $65,000 at December 31, 2004 and 2003, 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, 2004 and 2003, respectively, to pretax income is as follows:

	2004	2003	2002

Tax (benefit) computed at statutory rate	$ 1,207,874	$ 2,264,137	$ (65,459)

Increase (decrease) in taxes resulting from:
Net operating loss carryforwards used	-	(447,426)	-
State tax / percentage depletion / other	93,987	398,811	9,968
Other non deductible expenses	4,202	1,483	-

Provision (benefit)	$ 1,306,063	$ 2,217,005	$ 55,491

Effective Tax Rate	37.3%	33.5%	28.8%

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

	2004	2003	2002

Current tax provision (benefit) - federal	$ 125,003	$ 79,927	$ (55,491)
Current tax provision (benefit) - state	14,113	115,000	-
Deferred tax provision (benefit - federal	1,048,561	1,819,870	-
Deferred tax provision (benefit) - state	118,386	202,208	-

Total provision	$ 1,306,063	$ 2,217,005	$ (55,491)

Of the 2003 tax provision, $13,836 was attributable to the cumulative effect of the FAS 143 accounting change.

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NOTE 9 - REDEEMABLE PREFERRED STOCK

In 1993, Royale Energy's Board of Directors authorized the issuance of 259,250 shares of Series A Convertible Preferred Stock, which were sold through a private placement offering. The Series A Convertible Preferred Stock was offered in units. Each unit consisted of 25,000 shares of Series A Convertible Preferred Stock and a 0.1% interest in the distributions of the Royale Energy Income Trust, to be formed. Royale Energy had the right to sell fractional units. The Series A Convertible Preferred Stock has a stated value of $4 per share and provides shareholders with a one time 10% cash dividend payable thirty days after the expiration of one year from the date of purchase. The cash dividend has been paid on all outstanding shares at December 31, 1994. The Board authorized a 15% stock dividend to shareholders of record on May 31, 2002 and increased the number of Series A Preferred shares by 1,475. In addition, on May 1, 2003, the Board authorized a 15% stock dividen d to shareholders 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 A Preferred shares by 385 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 172 shares being issued. On March 23, 2004, the Board of Directors declared a 28% stock split, which was distributed to shareholders on June 30, 2004. As a result, the Series A Preferred shares increased by 1,339.

The Series A Convertible Preferred 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.

Royale Energy has the option to call, at any time, the Series A Convertible Preferred Stock at either the issue price of $4 per share plus 10%, if called within one year after issuance, or $4 per share thereafter. (Subject to the holders' conversion rights outlined above).

Upon the sale of 50% of the units of beneficial interest in Royal Energy Income Trust, a holder of Series A Convertible Preferred Stock may require Royale Energy to redeem their Series A Convertible Preferred Stock at the issue price of $4 per share plus accrued dividends, if any.

The Series A Convertible Preferred Stock has a liquidation preference to the common stock equal to $4 per share plus accrued dividends. Holders of Series A Convertible Preferred Stock shall have voting rights equal to the number of shares of common stock into which the Series A Convertible Preferred Stock may be converted.

On October 28, 1993, Royale Energy's Series A Convertible Preferred Stock shareholders were made a one time offer to convert their Series A Convertible Preferred Stock to common stock. This conversion would be at one share of common stock for each share of Series A Convertible Preferred Stock, rather than at the original conversion price of $4 per share. This conversion would not affect the shareholders' rights and incentives in the Royale Energy Income Trust. As of December 31, 2003 and 2002, 233,011 shares of Series A Convertible Preferred Stock had been converted to 202,723 shares of common stock. No conversions were made in 2004.

NOTE 10 - 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 shareholders' 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 shareholders 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 shareholders 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

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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 shareholders on June 30, 2004. As a result, the Series AA Preferred shares increased by 12,557. As of December 31, 2004, there were 57,416 shares issued and outstanding.

NOTE 11 - COMMON STOCK

Royale Energy's Board of Directors, at its December 1997 meeting, authorized the repurchase and cancellation of up to 15% of the outstanding common stock of Royale Energy. The Board also authorized a 15% stock dividend to shareholders of record on May 31, 2002. The number of common shares increased by 652,959 shares. The effect of the stock dividend decreased retained earnings by $4,472,769. In addition, on May 1, 2003, the Board of Directors authorized a 15% stock dividend to shareholders of record on that date with the dividend to be paid in equal quarterly installments beginning with the quarter ending June 30, 2003. The number of common shares increased by 585,924 shares after the third quarterly payment of the stock dividend. The effect of the stock dividend decreased retained earnings by $3,468,955 at December 31, 2003. On March 31, 2004, the fourth and final of these installments was made resulting in 221,049 shares being issued. On March 23, 2004, the Board of Directors d eclared a 28% stock split, which was distributed to shareholders on June 30, 2004. As a result, the number of common shares increased by 1,712,093.

The financial statements have been retroactively restated to reflect the stock split distributed in June 2004.

NOTE 12 - STOCK WARRANTS

Changes in Royale Energy's common stock warrants were as follows at December 31:

	2004	2003

Outstanding Warrants at Beginning of Period	340,514	304,909

15% Stock Dividend		35,605
Stock Reorganization	(340,514)	-

Outstanding Warrants at End of Period	-	340,514

On January 30, 2004, we issued a net 295,801 shares of common stock to Royale Petroleum Corporation, which is owned by our president, Donald H. Hosmer, and our Executive Vice President and Chief Financial Officer, Stephen M. Hosmer, upon exercise of options and warrants. The options and warrants were exercised in cashless exercises in which stock equal to the total exercise price of the securities was in effect withheld from the amount issued on exercise, based on the 5 day average closing price of the common stock for 5 days prior to exercise ($10.996 per share). Royale Petroleum Corporation exercised options and warrants to buy a total of 340,514 shares, bearing exercise prices from $1.02 to $2.03 per share, for the shares, for an aggregate consideration paid equal to $422,923. These shares were issued in reliance on the exemption from registration requirements provided by Section 4(2) of the Securities Act of 1933.

NOTE 13 - 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

F-25

$27,010 to $35,241, and the Woodland lease calls for monthly payments of $275. Future minimum lease obligations as of December 31, 2004 are as follows:

Year Ended
December 31,

2005		$ 215,804
2006		333,839
2007		343,854
2008		354,169
2009		364,795
Thereafter		2,248,936

Total		$ 3,861,397

Rental expense for the years ended December 31, 2004 and 2003, was $298,165 and $244,041, respectively.

NOTE 14 - RELATED PARTY TRANSACTIONS

Significant Ownership Interests

Donald H. Hosmer, Royale Energy's president, owns 12.99% 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 15.81% 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 and former officers and directors were billed $196,323 and $305,489 for their interests for the years ended December 31, 2004 and 2003, respectively. Under the Sarbanes-Oxley Act of 2002, these amounts can no longer be billed to officers and directors. Instead, these amounts are either collected in advance or paid to officers as compensation.

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

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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 2004, 2003 or 2002.

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.

A summary of the status of Royale Energy's stock option plan as of December 31, 2004 and 2003, and changes during the years ending on those dates is presented below:

	2004		2003
		Weighted-		Weighted-
		Average		Average
		Exercise		Exercise
	Shares	Price	Shares	Price

Fixed Options
Outstanding at Beginning of Year	114,439	$ 1.51	104,477	$ 1.79
Stock Dividends and Splits	35,849		13,622
Reinstated	19,996		39,675
Exercised	(33,141)		(43,335)
Expired or Ineligible	-		-

Outstanding at End of Year	137,143	$ 1.13	114,439	$ 1.51

Options Exercisable at Year End	137,143	$ 1.13	114,439	$ 1.51

Weighted-average Fair Value of Options
Granted During the Year	-		-

The following table summarizes information about fixed stock options outstanding at December 31, 2004 and 2003:

		Weighted-			Weighted-
	Number	Average		Number	Average
	Outstanding at	Remaining	Weighted-	Outstanding at	Remaining
Range of	December 31,	Contractual	Average	December 31,	Contractual
Exercise Prices	2004	Life (Years)	Exercise Price	2003	Life (Years)

$ 1.53	39,230	1	$ 1.53	34,685	2.0
$ 0.97	97,913	1	$ 0.97	79,754	1.9

$0.97 to $1.53	137,143	1	$0.97 to $1.53	114,439	1.4

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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, 2004 and 2003 were $46,043 and $42,875, 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 2004 or 2003.

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 - COMMITMENTS AND CONTINGENCIES

None

NOTE 18 - CONCENTRATIONS OF CREDIT RISK

The Company owns one property, Victor Ranch, which comprises 8.1% of the Company's entire gas reserves.

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.

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The Board of Directors

Royale Energy, Inc.

INDEPENDENT AUDITORS' REPORT ON SUPPLEMENTAL INFORMATION

Our report on our audit of the basic financial statements of Royale Energy, Inc. appears on page F-2. The audit was made for the purpose of forming an opinion on those statements taken as a whole. The supplemental material presented in the following section of this report is presented for purposes of additional analysis and is not a required part of the basic financial statements. We have applied certain limited procedures, which consisted principally of inquiries of management regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on it.

Sprouse & Anderson, LLP

February 18, 2005

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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, 2004 and 2003. 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, 2004, 2003 and 2002 and changes in such quantities during each of the years then ended, were as follows:

	2004		2003		2002
	Oil (BBL)	Gas (MCF)	Oil (BBL)	Gas (MCF)	Oil (BBL)	Gas (MCF)

Proved developed and undeveloped reserves:

Beginning of period	158,000	11,850,000	125,000	12,785,000	8,000	13,161,000
Revisions of previous estimates	(54,873)	(2,471,397)	9,614	(2,384,534)	(4,790)	(2,398,215)
Production	(20,017)	(1,870,250)	(22,160)	(1,915,784)	(7,617)	(1,585,578)
Extensions, discoveries and improved recovery	233,890	4,482,054	45,546	3,365,318	129,407	3,607,793
Purchase of minerals in place	-	633,593	-	-	-	-

Proved reserves end of period	317,000	12,624,000	158,000	11,850,000	125,000	12,785,000

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	2004		2003		2002
	Oil (BBL)	Gas (MCF)	Oil (BBL)	Gas (MCF)	Oil (BBL)	Gas (MCF)

Proved developed reserves:

Beginning of period	137,000	9,390,000	50,000	9,719,000	8,000	11,245,000

End of period	146,000	8,135,000	137,000	9,390,000	50,000	9,719,000

These estimates were determined using gas prices at December 31, 2004 ranging from $5.38 per MCF to $6.57 per MCF as applied on a field-by-field basis.

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

The standardized measure of discounted future net cash flows is presented below for the two years ended December 31, 2004.

The future net cash inflows are developed as follows:

(1)	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.
(2)	The estimated future production of proved reserves is priced on the basis of year-end prices.

(3)	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:


2005		$ 3,813,000
2006		2,774,000
2007		1,022,000
Thereafter		856,000

Total		$ 8,465,000

(4)	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.

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

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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.

	2004	2003	2002

Standardized measure - beginning of year	$ 24,114,126	$ 17,214,894	$ 9,013,270

Sales of oil and gas produced, net of production costs	(6,766,942)	(6,995,490)	(3,354,837)

Revisions of previous quantity estimates	(7,036,581)	(5,584,153)	(8,166,182)
Net changes in prices and production costs	5,498,228	7,651,000	13,271,000

Sales of minerals in place	-	-	(19,000)
Purchases of minerals in place	2,009,099	-	-

Extensions, discoveries and improved recovery	17,595,769	9,135,768	6,847,748

Accretion of discount	3,224,700	5,648,921	3,118,824

Net change in income tax	(4,357,282)	(2,956,814)	(3,495,929)

Net increase (decrease)	10,166,992	6,899,232	8,201,624

Standardized measure - end of year	$ 34,281,118	$24,114,126	$17,214,894

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 2005 through 2007.

Future development cost of:	2005	2006	2007
Proved developed reserves	$ 176,700	$ 48,335	$ 19,646
Proved non-producing reserves	307,056	26,590	2,470
Proved undeveloped reserves	3,329,132	2,699,500	999,750

Total	$ 3,812,888	$ 2,774,425	$1,021,866

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

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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 years ended December 31, 2004 and 2003, 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:

2004		$2,881,835
2003		$2,307,108
2002		$1,155,391

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