UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2012 Commission File No. 0-22750

ROYALE ENERGY, INC.

(Name of registrant in its charter)

California 33-0224120

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

7676 Hazard Center Drive, Suite 1500

San Diego, CA 92108

(Address of principal executive offices)

Issuer's telephone number: 619-881-2800

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

None

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

Common Stock, no par value per share

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the 

Securities Act. Yes  No 

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

Act. Yes  No 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 

15(d) of the Securities Exchange Act 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  No 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web 

site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of 

Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that 

the registrant was required to submit and post such files). Yes  No 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-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. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a nonaccelerated filer, or a smaller reporting company.

Large accelerated filer  Accelerated filer 

Non-accelerated filer  Smaller Reporting Company 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes 

 No 

At June 30, 2012, the end of the registrant’s most recently completed second fiscal quarter; the aggregate 

market value of common equity held by non-affiliates was $30,568,958.

At December 31, 2012, 12,545,465 shares of registrant's Common Stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: The issuer’s proxy statement for its annual meeting 

of stockholders, to be filed within 120 days after December 31, 2012, will contain the information required 

by Part III, Items 10, 11, 12, 13 and 14, which information is hereby incorporated by reference into this 

Form 10-K.
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The sole purpose of this amendment is to add to the annual report the information contained in Part III, 

which information is also contained in our preliminary proxy statement to be filed with the SEC on April 30, 

2013. No changes have been made in Parts I or II or in the audited financial statements contained in this 

Report.

TABLE OF CONTENTS

PART I 1

Item 1 Description of Business 1

Plan of Business 2

Competition, Markets and Regulation 3

Item 1A Risk Factors 4

Item 1B Unresolved Staff Comments 8

Item 2 Description of Property 8

Northern California 9

Developed and Undeveloped Leasehold Acreage 9

Drilling Activities 9

Production 10

Net Proved Oil and Natural Gas Reserves 11

Item 3 Legal Proceedings 11

Item 4 Mine Safety Disclosures 11

PART II 11

Item 5 Market for Common Equity and Related Stockholder Matters 11

Dividends 12

Recent Sales of Unregistered Securities 12

Performance Graph 12

Item 6 Management’s Discussion and Analysis of financial Condition and Results of Operations13

Critical Accounting Policies 13

Results of Operations for the Twelve Months Ended December 31, 2012, as Compared 

to the Twelve Months Ended December 31, 2011

15

Capital Resources and Liquidity 17

Changes in Reserve Estimates 19

Item 7 Qualitative and Quantitative Disclosures About Market Risk 19

Item 8 Financial Statements 19

Item 9 Changes in and Disagreements With Accountants on Accounting and Financial 

Disclosure

20

Item 9A Controls and Procedures 20

Disclosure Controls 20

Management Report on Internal Control over Financial Reporting 20

Changes in Internal Control over Financial Reporting 21

Limitations on Effectiveness of Controls 21

PART III 21

Item 10 Directors and Executive Officers of the Registrant 21

Item 11 Executive Compensation 24

Item 12 Security ownership of Certain Beneficial Owners and Management 27

Item 13 Certain Relationships and Related Transactions 28

Item 14 Principal Accountant Fees and Services 29

PART IV 30

Item 15 Exhibits and Financial Statement Schedules 30

SIGNATURES 32

FINANCIAL STATEMENTS F-1
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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 Capital Market 

System (symbol ROYL). On December 31, 2012, Royale Energy had 20 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, Oklahoma, Louisiana, and Alaska. Royale Energy usually sells a 

portion of the working interest in each well it drills or participates in to third party investors and retains a 

portion of the prospect for its own account. Selling part of the working interest to others allows Royale 

Energy to reduce its drilling risk by owning a diversified inventory of properties with less of its own funds 

invested in each drilling prospect, than if Royale Energy owned the whole working interest and paid all 

drilling and development costs of each prospect itself. Royale Energy generally sells working interests in its 

prospects to accredited investors in exempt securities offerings. The prospects are bundled into multi-well 

investments, which permit the third party investors to diversify their investments by investing in several 

wells at once instead of investing in single well prospects.

During its fiscal year ended December 31, 2012, Royale Energy continued to explore and develop natural 

gas properties with a concentration in California. We also completed the acquisition of approximately 

91,000 acres of prospective shale oil property in the north slope of Alaska. Additionally we own proved 

developed producing and non-producing reserves of oil and natural gas in Utah, Texas, Oklahoma and 

Louisiana. In 2012, Royale Energy drilled two wells in northern California; one was commercially 

productive which at year end was in the process of being completed and the other was a dry hole. Royale 

Energy's estimated total reserves increased from approximately 4.6 BCFE (billion cubic feet equivalent) at 

December 31, 2011 to approximately 4.9 BCFE at December 31, 2012. According to the reserve reports 

furnished to Royale Energy by Netherland, Sewell & Associates, Inc., and Source Energy, LLC, Royale 

Energy's independent petroleum engineers, the net reserve value of its proved developed and undeveloped 

reserves was approximately $7.6 million at December 31, 2012, based on natural gas prices ranging from 

$2.59 per MCF to $3.09 per MCF. Source Energy, LLC, supplied reserve value estimates for Royale 

Energy’s Utah properties, and Netherland, Sewell & Associates, Inc. provided reserve information for the 

Company’s California, Texas, Oklahoma and, Louisiana properties. 

 

Of course, net reserve value does not represent the fair market value of our reserves on that date, and we 

cannot be sure what return we will eventually receive on our reserves. Net reserve value of proved 

developed and undeveloped reserves was calculated by subtracting estimated future development costs, 

future production costs and other operating expenses from estimated net future cash flows from our 

developed and undeveloped reserves.

Our standardized measure of discounted future net cash flows at December 31, 2012, was estimated to be 

$3,937,621. This figure was calculated by subtracting our estimated future income tax expense from the net 

reserve value of proved developed and undeveloped reserves, and by further applying a 10% annual discount 

for estimated timing of cash flows. A detailed calculation of our standardized measure of discounted future 

net cash flow is contained in Supplemental Information about Oil and Gas Producing Activities – Changes 

in Standardized Measure of Discounted Future Net Cash Flow from Proved Reserve Quantities, page F-26.

Royale Energy reported gross revenues in connection with the drilling of wells on a "turnkey contract" basis 

in the amount of $2,028,863 for the year ended December 31, 2012, which represents approximately 46.2% 
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2

of its total revenues for the year. In 2011, Royale Energy reported $5,794,427 gross revenues from turnkey 

drilling operations for the year, representing 50.2% of Royale Energy's total revenues for that year.

These amounts are offset by drilling expenses and development costs of $449,536 in 2012, and $3,523,372 

in 2011. In addition to Royale Energy's own geological, land, and engineering staff, Royale Energy hires 

independent contractors to drill, test, complete and equip the wells that it drills. Approximately 38% of 

Royale Energy's total revenue for the year ended December 31, 2012, came from sales of oil and natural gas 

from production of its wells in the amount of $1,673,538, in 2011, this amount was $4,879,397, which 

represented 42% 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 stockholders are better served by diversification of its investments among individual 

drilling prospects. Through its sale of joint ventures, Royale Energy can acquire interests and develop oil 

and natural gas properties with greater diversification of risk and still receive an interest in the revenues and 

reserves produced from these properties. By selling some of its working interest in most projects, Royale 

Energy decreases the amount of its investment in the projects and diversifies its oil and gas property 

holdings, to reduce the risk of concentrating a large amount of its capital in a few projects that may not be 

successful.

After acquiring the leases or lease participation, Royale Energy drills or participates in the drilling of 

development and exploratory oil and natural gas wells on its property. Royale Energy pays its proportionate 

share of the actual cost of drilling, testing, and completing the project to the extent that it retains all or any 

portion of the working interest.

Royale Energy also may sell fractional working interests in undeveloped wells to finance part of the drilling 

cost. A drilling contract that calls for a company to drill a well, for a fixed price, to a specified depth or 

geological formation is called a "turnkey contract." When Royale Energy sells fractional working 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.

The fractional working interests that Royale Energy sells to investors are wellbore interests, in which the 

investor acquires the right to participate in drilling and production from a specific well being drilled on an 

oil and gas lease. When a wellbore interest is sold, the investor does not receive an interest in the larger 

leased property, which may include other potential drilling locations and additional development 

opportunities, but the investor does receive the rights in the leasehold as it relates to the wellbore, including 

rights and obligations to participate in drilling and production of the particular location in which he 

purchased the wellbore interest.

Although Royale Energy’s operating agreements do not usually address whether investors have a right to 

participate in subsequent wells in the same area of interest as a proposed well, it is the Company’s policy to 

offer to investors in a successful well the right to participate in subsequent wells at the same percentage level 

as their working interest investment in the prior successful well.

Our revenue recognition policy is to recognize all pre-drilling and drilling services we provide under turnkey 

drilling agreements at the time drilling of the well is completed. See Note 1 to our Financial Statements, at 

page F-8.

Once drilling has commenced, it is generally completed within 10-30 days. See Note 1 to Royale Energy's 
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3

Financial Statements, at page F-8. 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, 2012, Royale Energy earned gross revenues from operation of the wells in the 

amount of $455,396 representing 10.4% of its total revenues for the year. In 2011, the amount was 

$385,575, which represented about 3.3% of total revenues. At December 31, 2012, Royale Energy operated 

56 natural gas wells in California. Royale also owns an interest in seven natural gas wells in Utah and has 

non-operating interests in 11 oil and gas wells in Texas, two in Oklahoma, one in California, and one in 

Louisiana.

Royale Energy currently sells most of its California natural gas production through PG&E pipelines to 

independent customers on a monthly contract basis, while some gas is delivered through privately owned 

pipelines to independent customers. Since 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 fluctuated unpredictably throughout the year.

Royale Energy had no subsidiaries in 2012.

Competition, Markets and Regulation

Competition

The exploration and production of oil and natural gas is an intensely competitive industry. The sale of 

interests in oil and gas projects, like those Royale Energy sells, is also very competitive. Royale Energy 

encounters competition from other oil and natural gas producers, as well as from other entities which invest 

in oil and gas for their own account or for others, and many of these companies are substantially larger than 

Royale Energy.

Markets

Market factors affect the quantities of oil and natural gas production and the price Royale Energy can obtain 

for the production from its oil and natural gas properties. Such factors include: the extent of domestic 

production; the level of imports of foreign oil and natural gas; the general level of market demand on a 

regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of 

industrial production; political events in foreign oil-producing regions; and variations in governmental 

regulations including environmental, energy conservation, and tax laws or the imposition of new regulatory 

requirements upon the oil and natural gas industry.

Regulation

Federal and state laws and regulations affect, to some degree, the production, transportation, and sale of oil 

and natural gas from Royale Energy’s operations. States in which Royale Energy operates have statutory 

provisions regulating the production and sale of oil and natural gas, including provisions regarding 

deliverability. These statutes, along with the regulations interpreting the statutes, generally are intended to 

prevent waste of oil and natural gas, and to protect correlative rights to produce oil and natural gas by 

assigning allowable rates of production to each well or proration unit.
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4

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 some of these costs.

Presently, Royale Energy does not anticipate that compliance with federal, state and local environmental 

regulations will have a material adverse effect on capital expenditures, earnings, or its competitive position 

in the oil and natural gas industry; however, changes in the laws, rules or regulations, or the interpretation 

thereof, could have a materially adverse effect on Royale Energy’s financial condition or results of 

operation.

Royale Energy files quarterly, yearly and other reports with the Securities Exchange Commission. You may 

obtain a copy of any materials filed by Royale Energy with the SEC at 450 Fifth Street, N.W., Washington, 

D.C. 20549, by calling 1-800-SEC-0300. The SEC also maintains an Internet site that contains reports, 

proxy and information statements, and other information regarding issuers that file electronically with the 

SEC at http://www.sec.gov. Royale Energy also provides access to its SEC reports and other public 

announcements on its website, http://www.royl.com.

Item 1A Risk Factors

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

in evaluating our business.

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

Our success depends heavily upon our ability to market oil and gas production at favorable prices. In recent 

decades, there have been both periods of worldwide overproduction and underproduction of hydrocarbons 

and periods of increased and relaxed energy conservation efforts. As a result the world has experienced 

periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a 

domestic basis; these periods have been followed by periods of short supply of, and increased demand for, 

crude oil and, to a lesser extent, natural gas. The excess or short supply of oil and gas has placed pressures 

on prices and has resulted in dramatic price fluctuations.

Natural gas demand and the prices paid for gas are seasonal. The fluctuations in gas prices and possible new 

regulations create uncertainty about whether we can continue to produce gas for a profit.

Prices for oil and natural gas affect the amount of cash flow available for capital expenditures and our ability 

to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that 

we can economically produce. Any substantial and extended decline in the price of oil or natural gas would 

decrease our cash flows, as well as the carrying value of our proved reserves, our borrowing capacity and 

our ability to obtain additional capital.

The Depressed Price of Natural Gas Is Reducing Our Revenues and Our Reserves.

Large parts of our established production and reserves in California consist of natural gas. The price of 

natural gas has been depressed recently, and for 2012 the average sales price we received for natural gas was 
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5

$2.74 per MCF, compared to $4.08 in 2011. Lower gas prices caused a reduction in our revenues in 2012, 

and it also caused us to write down our total reserves, as yearend reserve values became less than book value 

of some existing wells. See Management’s Discussion and Analysis of Financial Condition and Results of 

Operations – Results of Operations for the Twelve Months Ended December 31, 2012, as Compared to the 

Twelve Months Ended December 31, 2011. If natural gas prices remain low, we may have further reductions 

to our production revenue from existing wells and further reductions in reserve values. Low natural gas 

prices also make exploration and development opportunities on our undeveloped properties in northern and 

central California less attractive.

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

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

the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a 

result, such estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, 

development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary 

substantially from those estimated in reserve reports that we periodically obtain from independent reserve 

engineers.

You should not construe the standardized measure of proved reserves contained in our annual report as the 

current market value of the estimated proved reserves of oil and gas attributable to our properties. In 

accordance with Securities and Exchange Commission requirements, we have based the standardized 

measure of future net cash flows from the standardized measure of proved reserves on the average price 

during the 12-month period before the ending date of the period covered by the report, whereas actual future 

prices and costs may vary significantly. The following factors may also affect actual future net cash flows:

· the timing of both production and related expenses;

· changes in consumption levels; and

· governmental regulations or taxation.

In addition, the calculation of the standardized measure of the future net cash flows using a 10% discount as 

required by the Securities and Exchange Commission is not necessarily the most appropriate discount rate 

based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas 

industry in general. Furthermore, we may need to revise our reserves downward or upward based upon 

actual production, results of future development, supply and demand for oil and gas, prevailing oil and gas 

prices and other factors.

Any significant variance in these assumptions could materially affect the estimated quantities and present 

value of our reserves. In addition, our standardized measure of proved reserves may be revised downward 

or upward, based upon production history, results of future exploration and development, prevailing oil and 

gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, 

development expenditures and operating expenses with respect to our reserves will likely vary from the 

estimates used, and such variances may be material.

Future Acquisitions and Development Activities May Not Result in Additional Proved Reserves, and 

We May Not be Able to Drill Productive Wells at Acceptable Costs.

In general, the volume of production from oil and gas properties declines as reserves are depleted. Except to 

the extent that we acquire properties containing proved reserves or conduct successful development and 

exploration activities, or both, our proved reserves will decline as reserves are produced. Our future oil and 

gas production is, therefore, highly dependent upon our ability to find or acquire additional reserves.
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6

The business of acquiring, enhancing or developing reserves is capital intensive. We require cash flow from 

operations as well as outside investments to fund our acquisition and development activities. If our cash 

flow from operations is reduced and external sources of capital become limited or unavailable, our ability to 

make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be 

impaired.

The Oil and Gas Industry has Mechanical and Environmental Risks.

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

no commercially productive oil or gas reservoirs will be encountered, that operations may be curtailed, 

delayed or canceled, and that title problems, weather conditions, compliance with governmental 

requirements, mechanical difficulties or shortages or delays in the delivery of drilling rigs and other 

equipment may limit our ability to develop, produce or market our reserves. New wells we drill may not be 

productive and we may not recover all or any portion of our investment in the well. Drilling for oil and gas 

may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not 

produce sufficient net revenues to return a profit after drilling, operating and other costs. In addition, our 

properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent 

properties.

Industry operating risks include the risks of fire, explosions, blow outs, pipe failure, abnormally pressured 

formations and environmental hazards, such as oil spills, natural gas leaks, ruptures or discharges of toxic 

gases, the occurrence of any of which could result in substantial losses due to injury or loss of life, severe 

damage to or destruction of property, natural resources and equipment, pollution or other environmental 

damage, clean up responsibilities, regulatory investigation and penalties and suspension of operations. In 

accordance with customary industry practice, we maintain insurance for these kinds of risks, but we cannot 

be sure that our level of insurance will cover all losses in the event of a drilling or production 

catastrophe. Insurance is not available for all operational risks, such as risks that we will drill a dry hole, fail 

in an attempt to complete a well or have problems maintaining production from existing wells.

Drilling is a Speculative Activity Even with Newer Technology.

Assessing drilling prospects is uncertain and risky for many reasons. We have grown in the past several 

years by using 3-D seismic technology to acquire and develop exploratory projects in northern California, as 

well as by acquiring producing properties for further development. The successful acquisition of such 

properties depends on our ability to assess recoverable reserves, future oil and gas prices, operating costs, 

potential environmental and other liabilities and other factors.

Nevertheless, exploratory drilling remains a speculative activity. Even when fully utilized and properly 

interpreted, 3-D seismic data and other advanced technologies assist geoscientists in identifying subsurface 

structures but do not enable the interpreter to know whether hydrocarbons are in fact present. In addition, 3-

D seismic and other advanced technologies require greater pre-drilling expenditures than traditional drilling 

strategies, and we could incur losses as a result of these costs.

Therefore, our assessment of drilling prospects are necessarily inexact and their accuracy inherently 

uncertain. In connection with such an assessment, we perform a review of the subject properties that we 

believe to be generally consistent with industry practices. Such a review, however, will not reveal all 

existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to 

fully assess their deficiencies and capabilities.

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

In most cases, we are not entitled to contractual indemnification for pre closing liabilities, including 

environmental liabilities, and we generally acquire interests in the properties on an "as is" basis with limited 

remedies for breaches of representations and warranties. In those circumstances in which we have 
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7

contractual indemnification rights for pre-closing liabilities, the seller may not fulfill those obligations and 

leave us with the costs.

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

Recoverable Reserves.

Competition for producing oil and gas properties is intense and many of our competitors have substantially 

greater financial and other resources than we do. Acquisitions of producing oil and gas properties may be at 

prices that are too high to be acceptable.

We Require Substantial Capital for Exploration and Development.

We make substantial capital expenditures for our exploration and development projects. We will finance 

these capital expenditures with cash flow from operations and sales of direct working interests to third party 

investors. We will need additional financing in the future to fund our developmental and exploration 

activities. Additional financing that may be required may not be available or continue to be available to 

us. If additional capital resources are not available to us, our developmental and other activities may be 

curtailed, which would harm our business, financial condition and results of operations.

Profit Depends on the Marketability of Production.

The marketability of our natural gas production depends in part upon the availability, proximity and capacity 

of natural gas gathering systems, pipelines and processing facilities. Most of our natural gas is delivered 

through natural gas gathering systems and natural gas pipelines that we do not own. Federal, state and local 

regulation of oil and gas production and transportation, tax and energy policies, and/or changes in supply 

and demand and general economic conditions could adversely affect our ability to produce and market its oil 

and gas. Any dramatic change in market factors could have a material adverse effect on our financial 

condition and results of operations.

We Depend on Key Personnel.

Our business will depend on the continued services of our co-presidents and co-chief executive officers, 

Donald H. Hosmer and Stephen M. Hosmer. Stephen Hosmer is also the chief financial officer. We do not 

have employment agreements with either Donald or Stephen Hosmer. The loss of the services of either of 

these individuals would be particularly detrimental to us because of their background and experience in the 

oil and gas industry.

The Oil and Gas Industry is Highly Competitive.

The oil and gas industry is highly competitive in all its phases. Competition is particularly intense with 

respect to the acquisition of desirable producing properties, the acquisition of oil and gas prospects suitable 

for enhanced production efforts, and the hiring of experienced personnel. Our competitors in oil and gas 

acquisition, development, and production include the major oil companies in addition to numerous 

independent oil and gas companies, individual proprietors and drilling programs.

Many of our competitors possess and employ financial and personnel resources far greater than those which 

are available to us. They may be able to pay more for desirable producing properties and prospects and to 

define, evaluate, bid for, and purchase a greater number of producing properties and prospects than we can. 

We must compete against these larger companies for suitable producing properties and prospects, to 

generate future oil and gas reserves.
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8

Governmental Regulations Can Hinder Production.

Domestic oil and gas exploration, production and sales are extensively regulated at both the federal and state 

levels. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, 

frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and 

state, have legal authority to issue, and have issued, rules and regulations affecting the oil and gas industry 

which often are difficult and costly to comply with and which carry substantial penalties for 

noncompliance. State statutes and regulations require permits for drilling operations, drilling bonds, and 

reports concerning operations. Most states where we operate also have statutes and regulations governing 

conservation matters, including the unitization or pooling of properties. Our operations are also subject to 

numerous laws and regulations governing plugging and abandonment, discharging materials into the 

environment or otherwise relating to environmental protection. The heavy regulatory burden on the oil and 

gas industry increases its costs of doing business and consequently affects its profitability. Changes in the 

laws, rules or regulations, or the interpretation thereof, could have a materially adverse effect on our 

financial condition or results of operation.

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

We sometimes acquire less than the controlling working interest in oil and gas properties. In such cases, it is 

likely that these properties would not be operated by us. When we do not have controlling interest, the 

operator or the other co-owners might take actions we do not agree with and possibly increase costs or 

reduce production income in ways we do not agree with.

Environmental Regulations Can Hinder Production.

Oil and gas activities can result in liability under federal, state and local environmental regulations for 

activities involving, among other things, water pollution and hazardous waste transport, storage, and 

disposal. Such liability can attach not only to the operator of record of the well, but also to other parties that 

may be deemed to be current or prior operators or owners of the wells or the equipment involved. We have 

inspections performed on our properties to assure environmental law compliance, but inspections may not 

always be performed on every well, and structural and environmental problems are not necessarily 

observable even when an inspection is undertaken.

Item 1B Unresolved Staff Comments

None

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 2012, Royale Energy drilled two wells in northern 

California, one of which was a developmental dry hole and the other was waiting completion of the pipeline 

at year end. In 2012, Royale Energy completed the acquisition of approximately 91,000 acres on the North 

Slope in a lease sale by the State of Alaska. Out of 13 companies bidding on 178 tracts, Royale won 56 

tracts in the heart of the oil window. The company's 91,040 acre position represents 27% of the 334,969 

acres leased in this sale.

Following industry standards, Royale Energy generally acquires oil and natural gas acreage without 

warranty of title except as to claims made by, though, 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.
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During 2012, Royale Energy maintained a revolving credit agreement with Texas Capital Bank, N.A. Under 

the terms of the agreement, Royale Energy may borrow, repay, and reborrow money from Texas Capital 

Bank with a total credit line of $14,250,000. The maximum allowable amount of each credit request is 

governed by a formula in the agreement. The maximum allowable amount at December 31, 2012, was 

$350,000. At December 31, 2012, Royale Energy owed $350,000 under this credit line. During January 

2013, the $350,000 loan balance was paid in full. In February 2013, the revolving credit agreement 

matured.

Following is a discussion of Royale Energy's significant oil and natural gas properties. Reserves at 

December 31, 2012, for each property discussed below, have been determined by Netherland, Sewell & 

Associates, Inc., and Source Energy, LLC, registered professional petroleum engineers, and in accordance 

with reports submitted to Royale Energy on February 12, 2013 and February 15, 2013, respectively.

Northern California

Royale Energy owns lease interests in eleven gas fields with locations ranging from Tehama County in the 

north to Kern County in the south, in the Sacramento and San Joaquin Basins in California. At December 

31, 2012, Royale operated 56 wells in California with estimated total proven, developed, and undeveloped 

reserves at approximately 4.9 BCF, according to Royale’s independently prepared reserve report as of 

December 31, 2012.

Developed and Undeveloped Leasehold Acreage

As of December 31, 2012, Royale Energy owned leasehold interests in the following developed and 

undeveloped properties in both gross and net acreage.

Developed Undeveloped

Gross 

Acres Net Acres

Gross 

Acres Net Acres

California 15,120.43 10,550.02 9,054.71 8,164.85

Alaska 0 0 91,039.59 91,039.59

All Other States 3,595.30 1,284.83 6,090.08 4,064.49

Total 18,715.73 11,834.85 106,184.38 103,268.93

Gross and Net Productive Wells

As of December 31, 2012, Royale Energy owned interests in the following oil and gas wells in both gross 

and net acreage:

Gross Wells Net Wells

Natural Gas 70.00 34.53

Oil 7.00 0.69

Total 77.00 35.22

Drilling Activities

The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2011 

and 2012. All wells are located in the Continental U.S., in California, Texas, Louisiana and Utah.
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10

Year Type of Well(a) Gross Wells(e) Net Wells(b)

Total Producing(c) Dry(d) Producing(c) Dry(d)

2011 Exploratory 1 0 1 0.0000 0.4965

Developmental 6 4 2 2.5184 0.9533

2012 Exploratory 1 1 0 0.5022 0.0000

Developmental 1 0 1 0.0000 0.4674

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.

As of December 31, 2012, Royale Energy was in the process of drilling one well in California and had 

recently finished drilling another California well.

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 6 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.

2012 2011

Net volume

Oil (BBL) 1,558 2,264

Gas (MCF) 559,590 1,144,469

MCFE 568,938 1,158,053

Average sales price

Oil (BBL) $ 90.75 $ 90.48

Gas (MCF) $ 2.74 $ 4.08

Net production costs and taxes $ 1,139,750 $ 1,517,920

Lifting costs (per MCFE) $ 2.00 $ 1.31
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Net Proved Oil and Natural Gas Reserves

As of December 31, 2012, Royale Energy had proved developed reserves of 3,188 MMCF and total proved 

reserves of 4,498 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 1 MBBL and total proved oil reserves of 63 

MBBL.

Oil and gas reserve estimates and the discounted present value estimates associated with the reserve 

estimates are based on numerous engineering, geological and operational assumptions that generally are 

derived from limited data.

Item 3 Legal Proceedings

National Fuel Corporation (“NFC”) v. Royale Energy, Inc., No. 080800735, Uintah County, Utah. NFC 

filed this lawsuit seeking to remove Royale as operator of the property in which Royale is the 75% record 

owner and operator and NFC was a non-operator with a 25% ownership. Trial was held on October 18-21, 

2011, at which Royale defended itself vigorously. On February 2, 2012, the Court issued its ruling, denying 

NFC’s request to remove Royale as operator. On April 6, 2012, judgment pursuant to the ruling was 

entered, and NFC filed an appeal. Effective February 1, 2013, during the pendency of the appeal, the case 

was settled. We anticipate that the appeal will be dismissed shortly, and the litigation concluded. There was 

no cash paid out as a result of the ruling.

Douglas Jones v. Royale Energy, Inc., et.al.

On July 1, 2010, Douglas Jones filed a lawsuit against the Company in the Circuit Court, 17th Judicial 

District, Broward County, Florida. Mr. Jones was an independent contractor handling certain aspects of 

sales for the Company prior to July 2, 2008. He asserts that he is entitled to an unspecified amount for 

commissions and expenses. The Company denies that any money is owed to Mr. Jones, and intends to 

defend the lawsuit vigorously. On August 16, 2010, the Company through Florida counsel Adam Hodkin, 

filed a motion to dismiss the lawsuit for lack of jurisdiction in the Florida courts. The Court has set the 

motion to dismiss for hearing on March 15, 2012, but the hearing was taken off calendar at the request of the 

plaintiff, Mr. Jones. The court then reset the motion for hearing on February 27, 2013. At the hearing, the 

judge took the matter under submission to consider whether he needed to hold an evidentiary hearing or 

whether he could rule on the papers. If the motion to dismiss is denied, Royale intends to answer their 

complaint and oppose the lawsuit vigorously.

Item 4 Mine Safety Disclosures

Not Applicable

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”. Since July 1, 2009, Royale Energy’s stock has been listed on the NASDAQ Capital 

Market, and prior to that, our stock was listed on the NASDAQ Global Market. As of December 31, 2012, 

12,545,465 shares of Royale Energy’s Common Stock were held by approximately 7,736 stockholders. The 

following table reflects the high and low quarterly closing sales prices from January 2011 through December 

2012.
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1st Qtr 2nd Qtr 3rd Qtr 4th Qtr

High Low High Low High Low High Low

2012 6.59 4.27 5.21 2.58 4.32 1.93 3.89 2.45

2011 7.83 2.08 5.52 2.56 3.91 2.08 5.36 1.90

Dividends

The Board of Directors did not issue cash or stock dividends in 2012 or 2011.

Recent Sales of Unregistered Securities

In February and March 2012, five directors exercised stock options to purchase a total of 76,346 shares of 

common stock in cashless exercises. The stock options had originally been awarded in 2008 at exercise 

prices of $3.50 per share. In February and March 2012, one director exercised stock options, which also had 

been awarded in 2008 and 2010, to purchase 45,000 and 43,692 shares of common stock for cash at an 

exercise price of $3.50 and $3.25 per share, respectively. The options had been issued and the stock was 

purchased in reliance on the exemption from registration requirements of the Securities Act of 1933 

contained in Section 4(2) thereof.

In November 2011, ownership of 31,667 shares of restricted common stock which had been awarded to the 

seven directors of Royale Energy for services rendered, vested. The restricted stock originally had been 

awarded in 2008 in reliance on the exemption from registration requirements of the Securities Act of 1933 

contained in Section 4(2) thereof. In March 2011, one director exercised stock options to purchase a total of 

18,440 shares of common stock in a cashless exercise. The stock options had originally been awarded in 

2008 at an exercise price of $3.50 per share.

Performance Graph

The following stock price performance graph is included in accordance with the SEC’s executive 

compensation disclosure rules and is intended to allow stockholders to review Royale Energy’s executive 

compensation policies in light of corresponding stockholder returns, expressed in terms of the appreciation 

of Royale Energy’s common stock relative to two broad-based stock performance indices. The information 

is included for historical comparative purposes only and should not be considered indicative of future stock 

performance. The graph compares total return on $100 value of Royale Energy’s common stock on 

December 31, 2006, with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index 

and the Dow Jones U.S. Oil & Gas Index from December 31, 2007 through December 31, 2012.
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13

2007 2008 2009 2010 2011 2012

Royale Energy, 

Inc. 100 100 95 80 164 92

S&P 500 Stock 

Index 100 62 76 86 86 97

DJ US Oil & Gas 

Index 100 63 73 85 87 90

Item 6 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 eighteen years, Royale Energy has primarily acquired and developed producing and nonproducing natural gas properties in California. In 2004, Royale Energy began developing leases in 

Utah. The most significant factors affecting the results of operations are (i) changes in oil and natural gas 

production levels and reserves, (ii) recording of turnkey drilling revenues and the associated drilling 

expense, and (iii) the change in commodities price of natural gas and oil reserves owned by Royale Energy.

Critical Accounting Policies

Revenue Recognition

Royale Energy’s financial statements include its pro rata ownership of wells. Royale Energy usually sells a 

portion of the working interest in each well it drills or participates in 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 as defined in FASB ASC 932-323-25.

Royale Energy has developed two profit-oriented segments of business: marketing direct working interests 

(DWI), and producing and selling oil and gas.

Royale Energy derives DWI revenue from sales of working interests in wells to be drilled to high net worth 

individuals. DWI investments relating to pre-drilling costs are non-refundable. The company holds all 

funds invested as deferred turnkey drilling until drilling is complete. Occasionally, drilling is delayed due to 

the permitting process or drilling rig availability. At December 31, 2012 and 2011, Royale Energy had 

deferred turnkey drilling of $8,693,743 and $6,909,666 respectively.

The primary business segment is oil and gas production. Northern and central California accounted for 

approximately 99% of the Company’s successful natural gas production in 2012. 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. 

Upon the sale or retirement of a complete field of a proved property, the Company eliminates the cost from 

its books, and the resultant gain or loss is recorded to Royale Energy’s Statement of Operations. Upon the 

sale of an entire interest in an unproved property where the property has been assessed for impairment 

individually, a gain or loss is recognized in Royale Energy’s Statement of Operations. If a partial interest in 

an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest 

retained.
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14

Oil and Gas Property and Equipment

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

accumulated on a field-by-field basis. These costs include pre-drilling activities such as leasing rents paid, 

drilling costs, and post-drilling tangible costs. Costs of unproved properties are excluded from amortization 

until the properties are evaluated. Royale Energy regularly evaluates its unproved properties on a field-byfield basis for possible impairment. Due to the unpredictable nature of exploration drilling activities, the 

amount and timing of impairment expenses are difficult to predict with any certainty.

Depletion

The units of production method of accounting uses proved reserves in the calculation of depletion, 

depreciation and amortization. Proved reserves are estimated quantities of crude oil, natural gas, and natural 

gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable 

from known reservoirs under existing economic and operating conditions. Proved reserves cannot be 

measured exactly, and the estimation of reserves involves judgment determinations. Independent 

engineering reserve estimates must be reviewed and adjusted periodically to reflect additional information 

gained from reservoir performance, new geological and geophysical data and economic changes. The 

estimates are based on current technology and economic conditions, and Royale Energy considers such 

estimates to be reasonable and consistent with current knowledge of the characteristics and extent of 

production. The independent engineering estimates include only those amounts considered to be proved 

reserves and do not include additional amounts which may result from new discoveries in the future, or from 

application of secondary and tertiary recovery processes where facilities are not in place or for which 

transportation and/or marketing contracts are not in place. Changes in previous estimates of proved reserves 

result from new information obtained from production history and changes in economic factors.

Impairment of Assets

Producing property costs are evaluated for impairment and reduced to fair value if the sum of expected 

undiscounted future cash flows is less than net book value pursuant to the Extractive Activities Topic of the 

Financial Accounting Standard Board’s (FASB) Accounting Standards Codification. Impairment of nonproducing leasehold costs and undeveloped mineral and royalty interests are assessed periodically on a 

property-by-property basis and any impairment in value are charged to expense. We periodically review for 

impairment of proved properties on a field-by-field basis. Unamortized capital costs are measured on a field 

basis and are reduced to fair value if it is determined that the sum of expected future net cash flows are less 

than the net book value. We determine if impairment has occurred through either adverse changes or as a 

result of its periodic review for impairment. Impairment is measured on a 10% discounted cash flows 

basis. We regard impairment costs of undeveloped properties as a component of our turnkey drilling 

overhead, since impairment costs amount to a write-down of previously acquired property inventory that we 

were unable to successfully develop as part of our turnkey drilling program.

Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the 

United States of America requires management to make estimates and assumptions that affect the reported 

amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial 

statements and the reported amounts of revenues and expenses during the reporting period. The most 

significant estimates pertain to proved oil, plant products and gas reserve volumes and the future 

development costs. Actual results could differ from those estimates.
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Deferred Income Taxes

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future 

deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the 

financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. All 

available evidence, both positive and negative, shall be considered to determine whether, based on the 

weight of that evidence, a valuation allowance for deferred tax assets is needed. Information about the 

company’s financial position and its results of operations for the current and preceding years will be used.

The company shall use judgment in considering the relative impact of negative and positive evidence. The 

weight given to the potential effect of negative and positive evidence shall be commensurate with the extent 

to which it can be objectively verified. The more negative evidence that exists, the more positive evidence is 

necessary and the more difficult it is to support a conclusion that a valuation allowance is not needed for 

some portion or all of the deferred tax asset. A cumulative loss in recent years is a significant piece of 

negative evidence that is difficult to overcome.

Future realization of a tax benefit sometimes will be expected for a portion, but not all of a deferred tax 

asset, and the dividing line between the two portions may be unclear. In those circumstances, application of 

judgment based on a careful assessment of all available evidence is required to determine the portion of a 

deferred tax asset for which it is more likely than not a tax benefit will not be realized.

Results of Operations for the Twelve Months Ended December 31, 2012, as Compared to the Restated 

Twelve Months Ended December 31, 2011

For the year ended December 31, 2012, we recorded a net loss before taxes of $4,526,117 a $1,394,630 

improvement when compared to a net loss before taxes of $5,920,747 during 2011. Total revenues from 

operations in 2012 were $4,394,745, a decrease of $7,137,665, or 61.9%, from the total revenues of 

$11,532,410 in 2011, the result of both lower turnkey drilling revenues and oil and natural gas sales. Total 

expenses from operations in 2012 were $8,741,001, a decrease of $9,333,701, or 51.6%, from the total 

expenses of $18,074,702 in 2011, due mainly to decreases in both drilling and impairment costs in 2012. At 

yearend 2012, management reviewed the realizability of the Company’s net deferred tax assets and 

concluded that certain conditions were met, as outlined above in the Certain Accounting Policy’s Deferred 

Income Tax section and in FASB ASC 740-10, under which it was appropriate for Royale to record a 

valuation allowance against the net deferred tax assets of $10,176,227, resulting in a net loss of $11,961,026 

in 2012 compared to a net loss of $4,188,241 in 2011.

In 2012, revenues from oil and gas production decreased by 65.7% to $1,673,538 from $4,879,397 in 2011, 

due to lower oil and natural gas production. This decrease in production was due to the natural declines of 

our existing wells and lower commodity prices received in 2012. The net sales volume of natural gas for the 

year ended December 31, 2012, was approximately 559,590 MCF with an average price of $2.74 per MCF, 

versus 1,144,469 MCF with an average price of $4.08 per MCF for 2011. This represents a decrease in net 

sales volume of 584,879 MCF or 51.1%. The net sales volume for oil and condensate (natural gas liquids) 

production was approximately 1,558 barrels with an average price of $90.75 per barrel for the year ended 

December 31, 2012, compared to 2,264 barrels at an average price of $90.48 per barrel for the year in 

2011. This represents a decrease in net sales volume of 706 barrels, or 31.2%. This decrease was mainly 

due to the sale of several oil producing wells in the first quarter of 2011.

Oil and gas lease operating expenses decreased by $378,170, or 24.9%, to $1,139,750 for the year ended 

December 31, 2012, from $1,517,920 for the year in 2011. This decrease was mainly due to lower 

transportation costs due to the decrease in production volumes and lower plugging costs during 2012. When 

measuring lease operating costs on a production or lifting cost basis, in 2012, the $1,139,750 equates to a 

$2.00 per MCFE lifting cost versus a $1.31 per MCFE lifting cost in 2011, a 52.7% increase, due to the 

lower production volumes in 2012.
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For the year ended December 31, 2012, turnkey drilling revenues decreased $3,765,564 to $2,028,863 from 

$5,794,427 in 2011, or 65.0%. We also had a $3,073,836 or 87.2% decrease in turnkey drilling and 

development costs to $449,536 in 2012 from $3,523,372 in 2011. These decreases in both turnkey revenues 

and costs were due to the drilling of two wells in 2012, one developmental and one exploratory well versus 

the drilling of seven wells in 2011, six developmental and one exploratory well. 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 increased to 77.8% from 39.2% for the 

years ended December 31, 2012 and 2011, 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 $200,778 and $4,529,058 were recorded in 2012 and 2011, respectively. In both years, 

we recorded impairments in wells or fields where year-end reserve values were less than the net book values 

of wells or where lease and land costs were no longer viable. In 2012, one Utah well and two California 

wells were impaired by $ 11,276 and $60,789 respectively. Also in 2012, we recorded lease impairments of 

$119,322 on various capitalized lease and land costs that were no longer viable. In 2011, two California 

fields, the Lonestar and Bowerbank fields were impaired $3,776,385 and $28,566, respectively, while our 

Utah field was also impaired by $710,124. These impairments were due to lower proved developed reserves 

than current book values primarily due to a substantial drop in the price of natural gas. Additionally in 

2011, we recorded lease impairments of $12,959 on various capitalized lease and land costs that were no 

longer viable.

Bad debt expense for 2012 and 2011 were $263,767 and $86,294, respectively. These expenses arose from 

identified uncollectable receivables relating to our oil and natural gas properties either plugged and 

abandoned or scheduled for plugging and abandonment. We periodically review our accounts receivable 

from working interest owners to determine whether collection of any of these charges where doubtful. By 

contract, the Company may not collect some charges from its Direct Working Interest owners for certain 

wells that ceased production or had been sold during the year, to the extent that these charges exceed 

production revenue

The aggregate of supervisory fees and other income was $692,344 for the year ended December 31, 2012, a 

decrease of $166,242 (19.4%) from $858,586 during the year in 2011. This decrease was mainly due to 

lower pipeline and compressor revenues generated from the decrease in natural gas production. Supervisory 

fees are charged in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for 

reimbursement of expenses associated with the joint accounting for billing, revenue disbursement, and 

payment of taxes and royalties. These charges are reevaluated each year and adjusted up or down as deemed 

appropriate by a published report to the industry by Ernst & Young, LLP, Certified Public 

Accountants. Supervisory fees increased $69,821 or 18.1%, to $455,396 in 2012 from $385,575 in 2011.

Depreciation, depletion and amortization expense decreased to $1,448,002 from $2,362,065 a decrease of 

$914,063 (38.7%) for the year ended December 31, 2012, as compared to 2011. The depletion rate is 

calculated using production as a percentage of reserves. This increase in depletion expense was due to the 

lower natural gas production during 2012 and a lower oil and gas asset base due to our 2011 impairments, 

resulting in a decreased depletion of our oil and natural gas properties.

General and administrative expenses decreased by $398,873 or 9.9%, from $4,039,209 for the year ended 

December 31, 2011, to $3,640,336 for the year in 2012. This decrease was primarily due to lower employee 

related costs. Legal and accounting expense decreased to $518,511 for the year, compared to $933,856 for 
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17

2011, a $415,345 or 44.5% decrease. This decrease was the result of lower legal fees in 2012 primarily 

related to the conclusion of the Mountain West and National Fuel litigation in 2011.

Marketing expense for the year ended December 31, 2012, decreased $119,377 or 16.7%, to $594,118, 

compared to $713,495 for the year in 2011. Marketing expense usually varies from period to period 

according to the number of marketing events attended by personnel and their associated costs. During 2012, 

in an effort to control costs, we attended fewer marketing conferences and attempted to negotiate lower 

conference fees.

During the years in 2012 and 2011, we incurred $423,459 and $111,390, respectively, in geological and 

geophysical costs in order to increase our oil and natural gas prospect base. These costs were incurred at the 

same seismic survey in Northern California. Additionally during 2012, we had a write down of $62,744 on 

certain oil and gas inventory to its estimated current market value. In 2011, we also had a write down of 

$258,043 on certain oil and gas pipeline inventory to its estimated current market value. In 2011, we sold 

our working interest in two separate non-core properties and other equipment resulting in a gain of 

$759,763. The properties were located in Kern County, California and Gaines County, Texas. 

During 2012, interest expense increased to $195,009 from $138,218 in 2011, a $56,791 or 41.1% 

increase. This increase was mainly due to the interest on a new convertible note payable obtained during the 

fourth quarter of 2012. Further details concerning Royale’s notes payable and line of credit usage can be 

found in the Capital Resources and Liquidity section below.

In 2012, we had income tax expense of $ 7,434,909 due to the valuation allowance recognized against our 

net deferred tax assets. In 2011, we had an income tax benefit of $ 1,732,506 due to our net loss before 

taxes of $ 5,920,747. For 2012, the use of a percentage depletion carryover valuation allowance created 

from the current and past operations results in an effective tax rate less than the normal federal rate of 34% 

plus the relevant state rates (mostly California, 9.3%).

Capital Resources and Liquidity

At December 31, 2012, Royale Energy had current assets totaling $6,540,592 and current liabilities totaling 

$ 15,886,654, a $6,978,713 working capital deficit. We had cash and cash equivalents at December 31, 

2012 of $1,489,930 compared to $2,946,131 at December 31, 2011.

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. 

The Company has traditionally relied on available credit and cash flows from operation for capital 

expenditures for oil and gas drilling and development, in addition to the cash generated from selling a 

portion of the working interest in prospects to third parties. As discussed in Results of Operations, page 14, 

the Company’s revenues both from oil and gas sales and from sales of working interests declined in 

2012. As a result of the decline in natural gas prices, we curtailed our drilling efforts in 2012, drilling only 

two wells in 2012, compared to seven wells in 2011. The decline in revenue also led the Company to seek 

alternative financing sources for its drilling activities.

To finance development of reserves, the Company took the following actions:

· In October 2012, the Company obtained $3 million from sale of a convertible note. See, 

The Company’s Prospectus Supplement filed pursuant to Rule 424(b) on October 29, 

2012, and the Company’s Form 8-K filed on October 29, 2012. The Company used these 
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18

proceeds for general corporate purposes, including the reduction of outstanding bank debt 

and for capital expenditures on oil and gas development. The note may, at the 

Company’s option, be repaid by converting the interest and principal amounts due to 

common stock, thus reducing the Company’s cash needs to service its debt.

· In February 2012, the Company entered into a sales agreement with C. K. Cooper & 

Company, Inc., to sell up to $10 million of common stock in an “at the market” offering 

as defined in Rule 415. In 2012, the Company sold approximately $4.6 million of 

common stock pursuant to the sales agreement. The Company expects to sell additional 

common stock pursuant to the sales agreement in 2013.

· Beginning in January 2012, the Company began extensive cost cutting measures in 

General and Administrative, Legal and Accounting, and Marketing expense. These 

measures enabled us to reduce our operating expenses by approximately $1 million for 

2012, compared to 2011, and expect that these measures will carry forward into 2013.

We expect that these measures will be sufficient to meet our liquidity demands for the foreseeable future.

At the end of 2012, our accounts receivable totaled $3,969,160 compared to $1,872,067 at December 31, 

2011, a $2,097,093 or 112.02% increase. This was primarily due to an approximately $2,500,000 

receivable, as part of the sale of common stock discussed above, due at December 31, 2012. This common 

stock receivable was collected on January 4, 2013. At December 31, 2012, our accounts payable and 

accrued expenses totaled $4,932,469, an increase of $389,728 or 8.6% over the accounts payable at the end 

of 2011 of $4,542,741. This increase was mainly due to increased drilling activity at year end 2012 when 

compared to year end 2011.

In February 2009, we entered into an agreement with Texas Capital Bank, N.A. for a new revolving line of 

credit and letter of credit facility, also secured by our oil and gas properties, of up to $14,250,000 and 

separate letter of credit facility of up to $750,000, 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 

scheduled maturity date for the loan was February 13, 2013. At December 31, 2012, we had a current 

borrowing base and outstanding indebtedness on this loan of $350,000. During January 2013, the balance of 

$350,000 on this credit facility was paid in full. In February 2013, the revolving credit agreement matured.

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

The following schedule summarizes our known contractual cash obligations at December 31, 2012, and the 

effect such obligations are expected to have on our liquidity and cash flow in future periods.

Total 

Obligations 2013 2014-2015 2016 Beyond

Office lease $ 1,066,614 $ 403,873 $ 662,741 $ - $ -

Revolving Line of Credit 350,000 350,000 - - -

Convertible Note 3,333,333 3,333,333

Total $ 4,749,947 $ 4,087,206 $ 662,741 $ - $ -

Operating Activities. For the years ended December 31, 2012 and 2011, cash provided by operating 

activities totaled $226,193 and $1,578,482, respectively. This difference in cash was from our lower oil and 

natural gas sales due to lower production volumes and price received during the year in 2012. 
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19

Investing Activities. For the year ended December 31, 2012, cash used by investing activities was 

$4,486,093 compared to $3,948,464 used by investing activities in 2011, an increase of $537,629 or 

13.6%. This increase in cash used was mainly due to finalizing and funding our agreement with the State of 

Alaska to obtain approximately 90,000 lease acres, in addition to the drilling two wells during 2012. In 

2011, we drilled or participated in the drilling of seven wells and received proceeds of $806,353 relating to 

the sale of certain oil and gas properties in Kern County, California and Gaines County, Texas. As part of 

the sale, we retained an overriding royalty interest in the acreage. 

Financing Activities. Net cash provided by financing activities totaled $2,803,699 and $601,488 for the 

years ended December 31, 2012 and 2011, respectively. The increase in cash provided was due to the 

obtaining of a new note payable and the sales of common stock during the year in 2012. In 2012, options 

were exercised by one director for a total of 88,692 shares of the Company’s common stock in exchange for 

proceeds of $299,500. Additionally during the year, Royale received proceeds, net of fees, of $2,119,510 

and issued 528,996 shares of its common stock relating to its market equity offering program. As discussed 

above, the Company received approximately $2.8 million from a convertible note payable during the year in 

2012. These proceeds were added to working capital and used for ordinary operating expense. Also during 

the period in 2012, five directors exchanged 195,000 options in a cashless exercise for 76,346 common 

shares. In 2011 several warrants were exchanged for shares of Royale’s common stock. Royale received 

$1,051,488 and issued 468,928 shares of its common stock relating to these exercises. Additionally during 

the period in 2011, we issued 18,440 shares of common stock to a member of the board of directors in a 

cashless stock options exercise.

Changes in Reserve Estimates

During 2012, our overall proved developed and undeveloped reserves decreased by 1.6% and our previously 

estimated proved developed and undeveloped reserve quantities were revised downward by approximately 

0.4 million cubic feet of natural gas. This downward revision was primarily due to two California wells, 

drilled in 2011, which had lower than previously estimated proved producing and non-producing natural gas 

reserves. See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-30.

During 2011, our overall proved developed and undeveloped reserves decreased by 25.5% and our 

previously estimated proved developed and undeveloped reserve quantities were revised downward by 

approximately 1 million cubic feet of natural gas. This downward revision was primarily due four 

California wells in our Lonestar field, one of which was drilled in 2009 and the other three drilled in 2010, 

which had lower than previously estimated proved producing and non-producing gas reserves.

Item 7 Qualitative and Quantitative Disclosures about Market Risk

Royale Energy is exposed to market risk from changes in commodity prices and in interest rates. In 2012, 

we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline. In 

2012, our natural gas revenues were approximately $1.5 million with an average price of $2.74 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 $150,000. At our current 

production levels of oil and natural gas condensate, a 10% increase or decrease in our average price per 

barrel could potentially increase or decrease our oil and natural gas revenues by approximately $14,100. We 

currently do not sell any of our natural gas or oil through hedging contracts.

Item 8 Financial Statements and Supplementary Data

See pages F-1, et seq., included herein.
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Item 9 Changes in and Disagreements with Accountants on Accounting and Financial 

Disclosure

None

Item 9A Controls and Procedures

Disclosure Controls

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 co-chief executive officers, Donald H. Hosmer and Stephen M. Hosmer (who is also our chief financial 

officer), evaluated the effectiveness or our disclosure controls and procedures as of the end of the 2012 fiscal 

year. Based on their evaluation, they concluded that our disclosure controls are effective as of December 31, 

2012.

Management Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial 

reporting to provide reasonable assurance regarding the reliability of our financial reporting and the 

preparation of financial statements for external purposes in accordance with generally accepted accounting 

principles. Internal control over financial reporting includes those policies and procedures that (i) pertain to 

the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and 

dispositions of the assets of the company, (ii) provide reasonable assurance that transactions are recorded as 

necessary to permit preparation of financial statements in accordance with generally accepted accounting 

principles, and that receipts and expenditures of the Company are being made only in accordance with 

authorizations of management and directors of the Company; and (iii) provide reasonable assurance 

regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s 

assets that could have a material effect on the financial statements. Management assessed our internal 

control over financial reporting as of December 31, 2012, which was the end of our fiscal year. Management 

based its assessment on criteria established in the SEC Commission Guidance Regarding Management’s 

Report on Internal Control Over Financial Reporting Under Section 13(a) or 15(d) of the Securities 

Exchange Act of 1934. The guidance sets forth an approach by which management can conduct a top-down, 

risk-based evaluation of internal control over financial reporting. Management’s assessment included an 

evaluation of risks to reliable financial reporting, whether controls exist to address those risks and evaluated 

evidence about the operation of the controls included in the evaluation based on its assessment of risk.

Based on our assessment, management has concluded that our internal control over financial reporting was 

effective as of the end of the fiscal year to provide reasonable assurance regarding the reliability of financial 

reporting and the preparation of financial statements for external reporting purposes in accordance with 

generally accepted accounting principles. We reviewed the results of management’s assessment with the 

Audit Committee of our Board of Directors.

This annual report does not include an attestation report of the company's registered public accounting firm 

regarding internal control over financial reporting. Management's report was not subject to attestation by the 

company's registered public accounting firm pursuant to temporary rules of the Securities and Exchange 

Commission that permit the company to provide only management's report in this annual report.
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Changes in Internal Control over Financial Reporting

No changes in our internal control over financial reporting occurred during the last fiscal quarter of 2012 

that have materially affected, or are reasonably likely to materially affect, our internal control over financial 

reporting.

Limitations on Effectiveness of Controls

Our management, including our CEO’s 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 been 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 have considered all 

possible future circumstances and events.

PART III

Item 10 Directors and Executive Officers of the Registrant

All of our directors serve one year terms from the time of their election to the time their successor is elected 

and qualified. The following information is furnished with respect to each director and executive officer 

who served as such during the fiscal year ended December 31, 2012:

Name Age

First 

Became 

Director or

Executive 

Officer Positions Held

Harry E. Hosmer 82 1986 Chairman of the Board

Donald H. Hosmer 59 1987

Co-President, Co-Chief Executive Officer 

and Director

Stephen M. Hosmer 46 1996

Co-President, Co-Chief Executive Officer, 

Chief Financial Officer, Secretary, and 

Director

Oscar A. Hildebrandt (1) (2) (3) 77 1995 Director

George M. Watters (1) (2) 93 1991 Director

Gary Grinsfelder (1), (3) 64 2007 Director

Tony Hall (2) (3) 71 2007 Director

(1) Member of the audit committee.

(2) Member of the compensation committee.

(3) Member of the nominations committee.

The board has determined that directors Gary Grinsfelder, Tony Hall, Oscar Hildebrandt, and George M. 

Watters qualify as independent directors under NASDAQ rules.
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The following summarizes the business experience of each director and executive officer for the past five 

years.

Harry E. Hosmer – Chairman of the Board

Harry E. Hosmer has served as chairman since Royale Energy began in 1986, and from inception in 1986 

until June 1995, he also served as president and chief executive officer.

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

Donald H. Hosmer has served as an executive officer and director of Royale Energy since its inception in 

1986. In June 1995 he became president and chief executive officer. In October 2008 he became copresident and co-chief executive officer, with primary responsibility for marketing and investor/shareholder 

relations for the company. Donald H. Hosmer is the son of Harry E. Hosmer and brother of Stephen M. 

Hosmer.

Stephen M. Hosmer – Co-President, Co-Chief Executive Officer, Chief Financial Officer, Secretary, 

and Director

Stephen M. Hosmer joined Royale Energy as the management information systems manager in May 1988, 

responsible for developing and maintaining Royale Energy’s computer software. Mr. Hosmer developed 

programs and software systems used by Royale Energy. From 1991 to 1995, he served as president of 

Royale Operating Company, Royale Energy’s operating subsidiary. In 1995, he became chief financial 

officer of Royale Energy. In 1996, he was elected to the board of directors of Royale Energy. In 2003, he 

was elected executive vice president. In October 2008, he became co-president and co-chief executive 

officer with primary responsibility for oil and gas exploration operations. Mr. Hosmer served seven years 

on the board of directors of Youth for Christ, a charitable organization in San Diego, California. Stephen M. 

Hosmer is the son of Harry E. Hosmer and brother of Donald H. Hosmer. Mr. Hosmer holds a Bachelor of 

Science degree in Business Administration from Oral Roberts University in Tulsa, Oklahoma, as well as 

earning his MBA degree via the prestigious President/Key Executive program at Pepperdine University in 

Malibu, California.

Oscar Hildebrandt, D.V.M. – Director

Dr. Hildebrandt served as an advisory member of Royale Energy’s board of directors from 1994 to 1995 and 

became a director in 1995. He serves as chairman of Royale Energy’s audit committee. Dr. Hildebrandt 

practiced veterinary medicine as President of Medford Veterinary Clinic, Medford, Wisconsin, from 1960 to 

1990. Since 1990, Dr. Hildebrandt has engaged independently in veterinary practice consulting 

services. He has served on the board of directors of Fidelity National Bank - Medford, Wisconsin, and its 

predecessor bank from 1965 to the present and is past chairman of the board of the Bank. From 1990 to the 

present he has acted as a financial advisor engaged in private business interests. Dr. Hildebrandt received a 

Bachelor of Science degree from the University of Wisconsin in 1954 and a Doctor of Veterinary Medicine 

degree from the University of Minnesota in 1958.

Gary Grinsfelder – Director

Mr. Grinsfelder is a geologist and manager with 38 years’ experience in oil and gas exploration, exploitation 

and property evaluation. Currently Mr. Grinsfelder is Vice President – Exploration of LeFrak 

Energy. Previously he was President of TXCO Resources. He has also served in geologic and management 

roles for Output Exploration, LLC, Araxas Exploration, Inc., Triad Energy Corporation, Spartan Petroleum 

Corporation, American Petrofina Company of Texas, Union Oil Company of California and Degolyer and 

MacNaughton. He received a Bachelor of Science degree in 1972 from Southern Methodist University and 
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has performed graduate studies at the University of Puerto Rico Department of Marine Science and 

University of Houston Department of Geology.

Tony Hall – Director

Ambassador Hall served as a member of the United States House of Representatives, representing the people 

of the Third District of Ohio, for almost twenty-four years, from 1979 to 2002. In 2002 he was appointed 

U.S. Ambassador to the United Nations Agencies for Food and Agriculture. He served as chief of the U.S. 

Mission to the U.N. Agencies in Rome – the Work Food Program, Food and Agriculture Organization and 

International Fund for Agricultural Development. He has been nominated for the Nobel Peace Prize on 

three occasions for his humanitarian and hunger-related work. He received his A. B. degree from 

Denison University, Granville, Ohio, in 1964.

George M. Watters – Director

Mr. Watters has been a Director of Royale Energy, Inc. since 1991. He has many years of senior 

management experience, including 23 years with Amoco, in all phases of downstream petroleum operations 

- marketing, refining, trading and commercial development. As CEO, he was instrumental in the conception 

and development of two successful grass roots refining and marketing projects in Australia and Singapore. 

His last assignment was Chief Executive of Amoco Shipping and Trading Company, residing in London. 

Prior to his affiliation with Amoco, he held various senior management positions with the former StandardVacuum Oil Company, jointly owned by Exxon and Mobil. He is a graduate of MIT and also attended their 

Management Program for Senior Executives. During World War II, Mr. Watters served four years as an 

officer in the U.S. Navy Civil Engineering Corps.

Audit Committee

The board has appointed an audit committee to assist the board of directors in carrying out its responsibility 

as to the independence and competence of the Company’s independent public accountants. In accordance 

with the rules of NASDAQ for listed companies, all members of the audit committee are independent 

members of the board of directors. The audit committee operates pursuant to an audit committee charger 

which has been adopted by the board of directors to define the committee’s responsibilities. A copy of the 

audit committee charter is posted on our website, www.royl.com. The board has determined that Oscar A. 

Hildebrandt qualifies as an “audit committee financial expert” as defined in Item 407(d) (5) of the Securities 

and Exchange Commission.

In 2012, the members of the audit committee were Oscar A. Hildebrandt, chair, George M. Watters and 

Gary Grinsfelder.

Code of Business Conduct and Ethics

We have adopted a code of business conduct and ethics for our directors and executive officers. The code is 

posted on our website, www.royl.com.

Compliance with Section 16(a) of the 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. 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 persons failed to file required reports on a timely basis for 2012.
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Item 11 Executive Compensation

The following table summarizes the compensation of the chief executive officer, chief financial officer and 

the two other most highly non-executive employees (the “named executives and employees”) of Royale 

Energy and its subsidiaries during the past year. No stock options, stock awards or other plan based 

compensation were made during 2012.

Name and 

Principal Position Year Salary Bonus

Stock 

Awards 

(1)

Option

Awards 

(2)

All Other 

Compens

ation (3) Total

($) ($) ($) ($) ($) ($)

Donald H. Hosmer 2012 $ 230,192 $ 6,906 $ 237,098

 Co-President and 

Co-CEO 2011 $ 230,192 $ 50,000 $ 16,550 $ 5,285 $ 8,406 $ 310,864

2010 $ 230,192 $ 50,000 $ 16,550 $ 9,344 $ 7,350 $ 313,436

Stephen M. Hosmer 2012 $ 230,192 $ 19,110 $ 249,302

 Co-President, CoCEO & CFO 2011 $ 230,192 $ 50,000 $ 16,550 $ 5,285 $ 20,766 $ 323,224

 2010 $ 231,205 $ 50,000 $ 16,550 $ 9,344 $ 19,350 $ 326,449

Mohamed AbdelRahmen (4) 2012 $ 204,615 $ 12,496 $ 217,085

 VP Exploration 2011 $ 204,615 $ 6,138 $ 210,753

2010 $ 198,365 $ 5,951 $ 204,316

Charles Tiano (4) 2012 $ 56,269 $ 138,450 $ 9,736 $ 204,455

 Director of 

Investor Relations 2011 $ 56,058 $ 225,348 $ 8,442 $ 289,848

 2010 $ 55,635 $ 168,858 $ 224,493

(1) On November 6, 2008, Donald H. Hosmer and Stephen M. Hosmer were each awarded 15,000 shares of 

common stock for services rendered during 2008. The closing price of Royale Energy’s common stock on 

that date was $3.31 per share. One third of the shares vested on November 6, 2009, 2010 and 2011.

(2) On March 23, 2008, Donald Hosmer and Stephen Hosmer (together with the other members of the board 

of directors) were each granted 45,000 options to purchase common stock at an exercise or base price of 

$3.50 per share. These options vested in three parts on March 31, 2008, 2009, and 2010. The options were 

granted for a legal life of four years with a service period of three years.

On December 10, 2010, Donald Hosmer and Stephen Hosmer (together with the other members of the board 

of directors) were each granted 50,000 options to purchase common stock at an exercise or base price of 

$3.25 per share. These options vested in two parts on January 1, 2011 and 2012. The options were granted 

for a legal life of five years with a service period of two years.

Amounts represent grant date fair value. See Note 12 of the financial statements contained in our annual 

report to shareholders on Form 10-K for the year ended December 31, 2011, regarding assumptions 

underlying the valuation of stock options. The fair value of the options was calculated using the BlackScholes option pricing method.

(3) All other compensation consists of matching contributions to the Company’s simple IRA plan, except 

for Stephen M. Hosmer, who also received a $12,000 car allowance.
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(4) Mr. Abdel-Rahmen and Mr. Tiano are highly compensated employees under SEC rules who did not 

serve as executive officers during 2011.

Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End

The following table presents the number of unexercised options at the 2012 year end for each named 

executive officer. No unvested stock awards were outstanding at the end of 2012.

Options

Name

Number of 

securities 

underlying 

unexercised 

options

(#)

exercisable

Number of 

securities 

underlying 

unexercised 

options

(#)

unexercisable

Option 

exercise 

price

($)

Option 

expiration 

date

Donald H. Hosmer 50,000(1) - $ 3.25 12/31/2015

Stephen M. Hosmer 50,000(1) - $ 3.25 12/31/2015

(1) In December 2010, the directors and executive officers of Royale Energy were each granted 50,000 

options to purchase common stock at an exercise or base price of $3.25 per share, in consideration of 

their past service on the board. These options vested and became exercisable over two years, on 

January 1, 2011 and 2012. They were granted for a period of five years with a service period of two 

years.

Compensation Committee Report

Our executive compensation committee has reviewed and discussed the following Compensation Discussion 

and Analysis with management and, based on its discussion and review, has recommended that the 

Compensation Discussion and Analysis be included in this proxy statement.

Members of the Compensation Committee:

Oscar A. Hildebrandt, Chair

Tony P. Hall

George M. Watters

In accordance with the rules of NASDAQ for listed companies, all members of the compensation committee 

are independent members of the board of directors.

Compensation Discussion and Analysis

Our executive compensation policy is designed to motivate, reward and retain the key executive talent 

necessary to achieve our business objectives and contribute to our long-term success. Our compensation 

policy for our executive officers focuses primarily on determining appropriate salary levels and 

performance-based cash bonuses.
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26

The elements of executive compensation at Royale Energy consist mainly of cash salary and, if appropriate, 

a cash bonus at yearend. The compensation committee makes recommendations to the board of directors 

annually on the compensation of the two top executives: Co-Presidents and the Co-Chief Executive Officers 

Donald H. Hosmer and Stephen M. Hosmer. We do not have employment contracts with either of our 

executive officers.

Royale Energy also does not provide extensive personal benefits to its executives beyond those benefits, 

such as health insurance, that are provided to all employees. Each executive does receive an annual car 

allowance.

Policy

The compensation committee’s primary responsibility is making recommendations to the board of directors 

relating to compensation of our officers. The committee also makes recommendations to the board of 

directors regarding employee benefits, our defined benefit plans, defined contribution plans, and stock based 

plans.

Determination

To determine executive compensation, the committee, in December each year, meets with our officers to 

review our compensation programs, discuss the performance of the company, the duties and responsibilities 

of each of the officers pay levels and business results compared to others similarly situated within the 

industry. The committee then makes recommendations to the board of directors for any adjustment to the 

officers’ compensation levels. The committee does not employ compensation consultants to make 

recommendations on executive compensation.

Compensation Elements

Base. Base salaries for our executive officers are established based on the scope of their responsibilities, 

taking into account competitive market compensation paid by our peers. Base salaries are reviewed 

annually. The salaries we paid to our most highly paid executive officers for the last three years are set forth 

in the Summary Compensation Table included under Executive Compensation.

Bonus. The compensation committee meets annually to determine the quantity, if any, of the cash bonuses 

of executive officers. The amount granted is based, subjectively, upon the company’s stock price 

performance, earnings, revenue, reserves and production. The committee does not use quantifiable metrics 

for these criteria; but rather uses each in balance to assess the strength of the company’s performance. The 

committee believes that formulaic approaches to cash incentives can foster an unhealthy balance between 

short-term and long-term goals. In 2012, the compensation committee did not award bonuses to the 

company’s executive officers.

Compensation of Directors

In 2012, none of the board members or committee member received fees for attendance at board meetings or 

committee meetings during the year. Royale Energy did reimburse directors for the expenses incurred for 

their services.

In addition, Royale Energy's Chairman of the Board and former President, Harry E. Hosmer, renders and 

receives compensation for management consulting services to Royale Energy on an ongoing basis. See 

Certain Relationships and Related Transactions, page 10.

The following table describes the compensation paid to our directors who are not also named executives for 

their services in 2012.
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27

Name

Fees earned

or paid in 

cash

Stock 

awards

Option 

awards

All Other 

Compensati

on (1) Total

($) ($) ($) ($) ($)

Harry E. Hosmer $ 138,050 $ 0 $ 0 $ 13,264 $ 151,314

Oscar A. Hildebrandt $ 0 $ 0 $ 0 $ 0

George M. Watters $ 0 $ 0 $ 0 $ 0

Gary Grinsfelder $ 0 $ 0 $ 0 $ 0

Tony P. Hall $ 0 $ 0 $ 0 $ 0

(1) Other compensation paid to Harry E. Hosmer in 2012 consisted of payments for medical and dental 

insurance coverage.

Item 12 Security Ownership of Certain Beneficial Owners and Management and Related 

Stockholder Matters

Common Stock

On March 31, 2013, 13,045,465 shares of Royale Energy’s common stock were outstanding.

The following table contains information regarding the ownership of Royale Energy’s common stock as of 

March 31, 2013, by:

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

shares of each class of equity securities;

ii) each director of Royale Energy, and

iii) all directors and officers of Royale Energy as a group. Except pursuant to applicable community 

property laws and except as otherwise indicated, each shareholder identified in the table possesses 

sole voting and investment power with respect to its or his shares. The holdings reported are based 

on reports filed with the Securities and Exchange Commission and the Company by the officers, 

directors and 5% shareholders pursuant to Section 16 of the Securities Exchange Act of 1934.

Stockholder (1) Number (2) Percent

Harry E. Hosmer, (3) 663,692 5.07%

Donald H. Hosmer, (3) 935,302 7.14%

Stephen M. Hosmer, (3) (4) 1,260,235 9.62%

Oscar A. Hildebrandt (2), (5) 153,936 1.15%

Gary Grinsfelder 45,440 *

Tony P. Hall 68,749 *

George M. Watters, (6) 154,477 1.17%

All officers and directors as a group 3,311,031 24.61%

* Less than 1%
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(1) The mailing address of each listed stockholder is 7676 Hazard Center Drive, Suite 1500, San Diego, 

California 92108.

(2) Includes options to purchase the following number of shares of common stock which were vested and 

exercisable on March 31, 2012: Harry E. Hosmer 50,000, Donald H. Hosmer 50,000; Stephen M. Hosmer 

50,000; Gary Grinsfelder 40,000; Tony Hall 50,000; Oscar A. Hildebrandt 6,308; George Watters 50,000.

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

(4) Includes 24,000 shares owned by Stephen M. Hosmer’s minor children.

(5) Includes 48,936 shares held by a trust.

(6) Includes 65,481 shares held by a trust.

Preferred Stock

Holders Series AA convertible preferred stock have voting rights equal to the number of shares into which 

they are convertible. On March 31, 2012, 52,784 shares of Series AA convertible preferred stock were 

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, 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 13 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, Oscar Hildebrandt and Tony Hall 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 ventures. 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 
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29

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 166 and 165 wells respectively under the 

1989 policy. The Hosmer Trust, a trust for the benefit of family members of Harry E. Hosmer, has 

participated in 164 wells.

Investments in wells under the 1989 policy for the three years ended December 31, 2012, 2011, and 2010 

are as follows:

Year

# of fractional 

interests Amount

Donald Hosmer 2012 2 $ 4,186

2011 7 $ 42,636

2010 8 $ 37,841

Stephen Hosmer 2012 2 $ 2,537

2011 7 $ 37,885

2010 8 $ 23,941

Hosmer Trust 2012 2 $ 2,537

2011 7 $ 34,033

2010 8 $ 25,093

Current officers and directors were billed 3,451, $23,010 and $15,387 for their interests for the three years 

ended December 31, 2012, 2011, and 2010, respectively.

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 

$138,050, $168,882 and $169,824 for his consulting services in 2012, 2011, and 2010, respectively, 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 14 Principal Accountant Fees and Services

Padgett Stratemann LLP served as the independent auditors to audit the Company’s financial statements for 

the fiscal year ended December 31, 2012. The aggregate fees billed by them for the years ended December 

31, 2012 and 2011 are as follows:

2012 2011

Audit fees (1) $ 110,299 $ 113,650

Tax fees (2) - -

All other fees (3) $ 31,350 $ 1,400

Total $ 141,649 $ 115,050

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

(3) Other fees consist of work on registration statements under the Securities Act of 1933.
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30

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.

No representatives of Padgett Stratemann LLP are expected to be present at the annual meeting. Although 

the audit committee has the sole responsibility to appoint the auditors as required under the Securities 

Exchange Act of 1934, the committee welcomes any comments from shareholders on auditor selection or 

performance. Comments may be sent to the audit committee chair, Dr. Oscar A. Hildebrandt, care of Royale 

Energy’s executive office, 7676 Hazard Center Drive, Suite 1500, San Diego, California 92108.

PART IV

Item 15 Exhibits and Financial Statement Schedules

The agreements included as exhibits to this report are included to provide information about their terms and 

not to provide any other factual or disclosure information about Royale Energy or the other parties to the 

agreements. The agreements contain representations and warranties by each of the parties to the applicable 

agreement that were made solely for the benefit of the other agreement parties and:

 should not be treated as categorical statements of fact, but rather as a way of allocating the risk 

among the parties if those statements prove to be inaccurate;

 have been qualified by disclosures that were made to the other party in connection with the 

negotiation of the applicable agreement, which disclosures are not necessarily reflected in the 

agreement;

 may apply standards of materiality in a way that is different from the way investors may view 

materiality; and

 were made only as of the date of the applicable agreement or such other date or dates as may be 

specified in the agreement and are subject to more recent developments.

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

2. Schedules. Supplemental Information About Oil and Gas Producing Activities (Unaudited) begins 

on page F-26.

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

1.1 Placement Agent Agreement between the Company and C.K. Cooper & Company, Inc., dated 

October 25, 2012, incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed 

October 29, 2012.

3.1 Restated Articles of Incorporation of Royale Energy, Inc., incorporated by reference to Exhibit 3.1 

of Royale Energy’s Form 10-Q filed August 14, 2009.

3.2 Amended and Restated Bylaws of Royale Energy, Inc., incorporated by reference to Exhibit 3.2 of 

Royale Energy’s Form 10-K filed March 27, 2009.

4.1 Series A-1 Warrant issued to Cranshire Capital, L.P., incorporated by reference to Exhibit 4.2 of the 

Company’s Form 8-K filed August 6, 2009.

4.2 Series C Warrant issued to Cranshire Capital, L.P., incorporated by reference to Exhibit 4.4 of the 

Company’s Form 8-K filed August 6, 2009.
Table of Contents

31

4.3 Series D Warrant issued to Cranshire Capital, L.P., incorporated by reference to Exhibit 4.1 of the 

Company’s Form 8-K filed October 21, 2009.

4.4 Series E Warrant issued to certain affiliates of Cranshire Capital, L.P., incorporated by reference to 

Exhibit 4.2 of the Company’s Form 8-K filed October 29, 2012.

4.5 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.

10.2 Amended and Restated Credit Agreement between Royale Energy and Texas Capital Bank, N.A. 

(February 13, 2009), incorporated by reference to Exhibit 310.2 of Royale Energy’s Form 10-K 

filed March 27, 2009.

10.3 Form of Promissory Note between Royale Energy and Texas Capital Bank, N.A., incorporated by 

reference to Exhibit 10.3 of Royale Energy’s Form 10-K filed March 27, 2009.

10.4 Securities Purchase Agreement between the Company and Cranshire Capital, L.P., dated as of 

August 4, 2009, incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed August 

6, 2009.

10.5 Registration Rights Agreement between the Company and Cranshire Capital, L.P., dated as of 

August 5, 2009, incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed August 

6, 2009.

10.6 Securities Purchase Agreement between the Company and Cranshire Capital, L.P., dated as of 

October 16, 2009, incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed 

October 21, 2009.

10.7 Registration Rights Agreement between the Company and Cranshire Capital, L.P., dated as of 

October 16, 2009, incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed 

October 21, 2009.

10.8 Sales Agreement between the Company and C.K. Cooper & Company, Inc., dated February 17, 

2012, incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed February 17, 

2012.

10.9 Securities Purchase Agreement between the Company and certain buyers dated as of October 28, 

2012, incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K filed October 29, 

2012.

10.10 Convertible Note issued to certain affiliates of Cranshire Capital, L.P., incorporated by reference 

to Exhibit 4.1 of the Company’s Form 8-K filed October 29, 2012.

23.1 Consent of Padgett, Stratemann & Co., L.L.P., filed herewith.

23.2 Consent of Netherland, Sewell & Associates, Inc., filed herewith.

23.3 Consent of Source Energy, LLC, filed herewith.

31.1 Rule 13a-14(a), 115d-14(a) Certification, filed herewith.

31.2 Rule 13a-14(a), 115d-14(a) Certification, filed herewith.

32.1 Section 1350 Certification, filed herewith.

32.2 Section 1350 Certification, filed herewith.

99.1 Report of Netherland Sewell & Associates, Inc., filed herewith.

99.2 Report of Source Energy, LLC, filed herewith.

99.3 Waiver Letter from Cranshire Capital, L.P. to the Company dated October 28, 2012, incorporated 

by reference to Exhibit 99.1 of the Company’s Form 8-K filed October 29, 2012.

101.INS* XBRL Instance Document

101.SCH* XBRL Taxonomy Extension Schema

101.CAL* XBRL Taxonomy Extension Calculation Linkbase

101.DEF* XBRL Taxonomy Extension Definition Linkbase

101.LAB* XBRL Taxonomy Extension Label Linkbase

101.PRE* XBRL Taxonomy Extension Presentation Linkbase
Table of Contents

32

* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a 

registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or 

Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant 

has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Royale Energy, Inc.

Date: April 30, 2013 /s/ Donald H. Hosmer

Donald H. Hosmer

Co-President and Co-Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the 

following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: April 30, 2013 /s/ Harry E. Hosmer

Harry E. Hosmer

Chairman of the Board of Directors

Date: April 30, 2013 /s/ Donald H. Hosmer

Donald H. Hosmer

Director, Co-President, Co-Chief Executive Officer

Date: April 30, 2013 /s/ Stephen M. Hosmer

Stephen M. Hosmer

Director, Co-President, Co-Chief Executive Officer, Chief Financial 

Officer and Secretary

Date: April 30, 2013 /s/ Tony Hall

Tony Hall

Director

Date: April 30, 2013 /s/ Oscar A. Hildebrandt

Oscar A. Hildebrandt

Director

Date: April 30, 2013 /s/ Gary Grinsfelder

Gary Grinsfelder

Director

Date: April 30, 2013 /s/ George M. Watters

George M. Watters

Director
Table of Contents

F-1

ROYALE ENERGY, INC. 

INDEX TO FINANCIAL STATEMENTS 

AND SUPPLEMENTARY DATA

TABLE OF CONTENTS

REPORT OF PADGETT, STRATEMANN & CO., LLP, INDEPENDENT AUDITORS F-2

BALANCE SHEETS F-3

STATEMENTS OF COMPREHENSIVE LOSS F-5

STATEMENTS OF STOCKHOLDERS’ EQUITY F-6

STATEMENTS OF CASH FLOWS F-9

NOTES TO FINANCIAL STATEMENTS F-11
Table of Contents

F-2

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders

 of Royale Energy, Inc.

We have audited the accompanying balance sheets of Royale Energy, Inc. (the “Company”) as of December 

31, 2012 and 2011, and the related statements of comprehensive loss, stockholders' equity, and cash flows 

for the years then ended. These financial statements are the responsibility of the Company's management. 

Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight 

Board (United States). Those standards require that we plan and perform the audit to obtain reasonable 

assurance about whether the financial statements are free of material misstatement. The Company is not 

required to have, nor were we engaged to perform an audit of its internal control over financial reporting. 

Our audits included consideration of internal control over financial reporting as a basis for designing audit 

procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the 

effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such 

opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures 

in the financial statements, assessing the accounting principles used and significant estimates made by 

management, as well as evaluating the overall financial statement presentation. We believe that our audits 

provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial 

position of Royale Energy, Inc. as of December 31, 2012 and 2011, and the results of its operations and its 

cash flows for the years then ended in conformity with accounting principles generally accepted in the 

United States of America.

As disclosed in Note 19 to the financial statements, the 2011 financial statements have been restated to 

reflect the correction of an error related to revenue recognition.

Padgett, Stratemann & Co., L.L.P.

San Antonio, Texas

April 15, 2013
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F-3

ROYALE ENERGY, INC

BALANCE SHEETS

DECEMBER 31, 2012 AND 2011

ASSETS

2012

2011-

Restated

Current Assets

Cash and Cash Equivalents $ 1,489,930 $ 2,946,131

Accounts Receivable, net 3,969,160 1,872,067

Prepaid Expenses 469,038 432,168

Deferred Tax Asset 0 661,645

Available for Sale Securities 0 31,027

Inventory 612,464 664,458

Total Current Assets 6,540,592 6,607,496

Other Assets 6,946 6,946

Deferred Tax Asset - Noncurrent 0 6,771,474

Oil And Gas Properties (Successful Efforts Basis) and

Equipment and Fixtures 10,955,797 8,075,344

Total Assets $ 17,503,335 $ 21,461,260

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

F-4

ROYALE ENERGY, INC.

BALANCE SHEETS

DECEMBER 31, 2012 AND 2011

LIABILITIES AND STOCKHOLDERS' EQUITY

2012

2011-

Restated

Current Liabilities:

Accounts Payable and Accrued Expenses $ 4,932,468 $ 4,542,741

Current Portion of Long-Term Debt, Net 2,258,668 0

Current Portion of Deferred Tax Liability 1,775 1,240

Deferred Revenue from Turnkey Drilling 8,693,743 6,909,666

Total Current Liabilities 15,886,654 11,453,647

Noncurrent Liabilities:

Asset Retirement Obligation 954,088 575,612

Long-Term Debt 0 2,750,000

Total Noncurrent Liabilities 954,088 3,325,612

Total Liabilities 16,840,742 14,779,259

Stockholders' Equity

Common Stock, No Par Value, 20,000,000 Shares Authorized; 12,545,465 

and 10,823,050 Shares Issued, 12,545,465 and 10,790,431 Shares 

Outstanding, Respectively 33,247,571 28,298,228

Convertible Preferred Stock, Series AA, No Par Value, 147,500 Shares 

Authorized; 52,784 Shares Issued and Outstanding, Respectively 154,014 154,014

Accumulated (Deficit) (34,186,930) (22,225,904)

Paid in Capital 1,447,938 632,004

Accumulated Other Comprehensive Income 0 3,035

Total Paid in Capital and Accumulated 

Deficit 662,593 6,861,377

Less Cost of Treasury Stock, 0 and 32,619 Shares, respectively 0 (179,376)

Total Stockholders' Equity 662,593 6,682,001

Total Liabilities and Stockholders' Equity $ 17,503,335 $ 21,461,260

The accompanying notes are an integral part of these financial statements.
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F-5

ROYALE ENERGY, INC.

STATEMENTS OF COMPREHENSIVE LOSS

FOR THE YEARS ENDED DECEMBER 31, 2012, AND 2011

2012

2011-

Restated

Revenues:

Sale of Oil and Gas $ 1,673,538 $ 4,879,397

Turnkey Drilling 2,028,863 5,794,427

Supervisory Fees and Other 692,344 858,586

Total Revenues $ 4,394,745 $ 11,532,410

Costs and Expenses:

General and Administrative 3,640,336 4,039,209

Turnkey Drilling & Development 449,536 3,523,372

Lease Operating 1,139,750 1,517,920

Lease Impairment 200,778 4,529,058

Geological and Geophysical 423,459 111,390

Inventory Write Down 62,744 258,043

Bad Debt Expense 263,767 86,294

Legal and Accounting 518,511 933,856

Marketing 594,118 713,495

Depreciation, Depletion and Amortization 1,448,002 2,362,065

Total Costs and Expenses $ 8,741,001 $ 18,074,702

Gain on Sale of Assets 8,100 759,763

Loss from Operations (4,338,156) (5,782,529)

Other Income (Expense):

Interest Expense (195,009) (138,218)

Gain on sale of Marketable Securities 7,048 0

Income (Loss) Before Income Tax Expense (4,526,117) (5,920,747)

Income Tax Expense (Benefit) 7,434,909 (1,732,506)

Net Loss $ (11,961,026) $ (4,188,241)

Basic Earnings Per Share:

Net Loss Available To Common Stock $ (1.07) $ (0.39)

Diluted Loss Per Share $ (1.07) $ (0.39)

Other Comprehensive Income

 Unrealized Gain on Equity Securities $ 0 $ 4,275

 Less: Reclassification Adjustment for Gains Included in Net Income (3,035) 0

Other Comprehensive Income , before tax (3,035) 4,275

Income Tax Expense Related to Items of Other Comprehensive Income 0 1,240

Other Comprehensive Income (Loss), net of tax (3,035) 3,035

Comprehensive Loss $ (11,964,061) $ (4,185,206)

The accompanying notes are an integral part of these financial statements.
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F-6

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2012, and 2011

Common Stock Preferred Stock Series AA

Shares 

Issued Amount Shares Outstanding Amount

Balance, December 31, 2010, 

as previously reported 10,307,350 $ 27,246,740 52,784 $ 154,014

Prior period adjustment

Balance, December 31, 2010, 

as restated 10,307,350 27,246,740 52,784 154,014

Common Stock Warrant 

Exercise 468,928 $ 1,051,488 - -

Directors’ Stock Option Grant 18,440 - - -

Directors’ Stock Grant 28,332 - - -

Available for Sale Securities –

Unrealized Gain (Loss), net of 

tax

- - - -

Net Loss (Restated)

Balance, December 31, 2011-

Restated 10,823,050 $ 28,298,228 52,784 $ 154,014

Common Stock Options 

Exercise 165,038 $ 299,500 - -

Directors’ Stock Options 

Grant - - - -

Common Stock Private 

Placement Sale 1,562,352 $ 4,649,843 - -

Treasury Stock Retirement (4,975) - - -

Discount on Warrant Value - - - -

Treasury Stock Donation - - - -

Available for Sale Securities –

Realized Gain, net of tax - - - -

Net Loss - - - -

Balance, December 31, 2012 12,545,465 $ 33,247,571 52,784 $ 154,014

The accompanying notes are an integral part of these financial statements.
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F-7

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2012, and 2011

Treasury Stock

Shares 

Acquired Amount Paid in Capital

Accumulated 

Deficit

Balance, December 31, 2010, 

as previously reported 32,619 $ (179,376 ) $ 524,406 $ (16,807,424 )

Prior period adjustment (1,230,239 )

Balance, December 31, 2010, 

as restated 32,619 (179,376 ) 524,406 (18,037,663 )

Common Stock Warrant 

Exercise - - - -

Directors’ Stock Option Grant - - 40,015 -

Directors’ Stock Grant - - 67,583 -

Available for Sale Securities –

Unrealized Gain (Loss), net of 

tax

- - - -

Net Loss (Restated) (4,188,241 )

Balance, December 31, 2011-

Restated 32,619 $ (179,376 ) $ 632,004 $ (22,225,904 )

Common Stock Options 

Exercise - - - -

Directors’ Stock Options 

Grant - - 39,260 -

Common Stock Private 

Placement Sale (26,644 ) $ 146,515 (174,451 ) -

Treasury Stock Retirement (4,975 ) $ 27,361 (173,876 ) -

Discount on Warrant Value - - 1,127,111 -

Treasury Stock Donation (1,000 ) $ 5,500 (2,110 ) -

Available for Sale Securities –

Realized Gain, net of tax - - - -

Net Loss (11,961,026 )

Balance, December 31, 2012 0 $ 0 $ 1,447,938 $ (34,186,930 )

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

F-8

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2012, and 2011

Accumulated 

Other 

Comprehensive 

Income (Loss)

Total

Balance, December 31, 2010, as 

previously reported $ 0 $ 10,938,360

Prior period adjustment (1,230,239 )

Balance, December 31, 2010, as 

restated 0 9,708,121

Common Stock Warrant 

Exercise - 1,051,488

Directors’ Stock Option Grant - 40,015

Directors’ Stock Grant - 67,583

Available for Sale Securities –

Unrealized Gain (Loss), net of 

tax

3,035 3,035

Net Loss (Restated) (4,188,241 )

Balance, December 31, 2011-

Restated $ 3,035 $ 6,682,001

Common Stock Options 

Exercise - 299,500

Directors’ Stock Options Grant - 39,260

Common Stock Private 

Placement Sale - 4,621,907

Treasury Stock Retirement - (146,515 )

Discount on Warrant Value - 1,127,111

Treasury Stock Donation - 3,390

Available for Sale Securities –

Realized Gain, net of tax (3,035 ) (3,035 )

Net Loss (11,961,026 )

Balance, December 31, 2012 $ 0 $ 662,593

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

F-9

ROYALE ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2012, and 2011

2012

2011-

Restated

CASH FLOWS FROM OPERATING ACTIVITIES:

Net Loss $ (11,961,026 ) $ (4,188,241)

Adjustments to Reconcile Net Loss to Net Cash Provided by Operating 

Activities:

Depreciation, Depletion, and Amortization 1,448,002 2,362,065

Lease Impairment 200,778 4,529,058

(Gain) Loss on Sale of Assets (8,100) (759,763)

Realized (Gain) Loss on Equity Securities (7,048) 0

Bad Debt Expense 263,767 86,294

Stock-Based Compensation 39,260 107,598

Debt Discount Amortization, 100,779 0

Inventory Write Down 62,744 258,043

Treasury Stock Donation 3,390 0

(Increase) Decrease in:

Deferred Income Taxes 7,433,654 (1,735,594)

Accounts Receivable 145,333 492,686

Prepaid Expenses and Other Assets (47,620) 82,202

Increase (Decrease) in:

Accounts Payable and Accrued Expenses 768,203 (724,133)

Deferred Revenues - DWI 1,784,077 1,152,170

Net Cash Provided by Operating Activities 226,193 1,662,385

CASH FLOWS FROM INVESTING ACTIVITIES:

Expenditures For Oil And Gas Properties and 

 Other Capital Expenditures (4,536,358) (4,754,817)

Proceeds from Sale of Assets 14,690 806,353

Sale of Equity Securities 35,575 0

Net Cash Used in Investing Activities (4,486,093) (3,948,464)

CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from Long-Term Debt 2,784,689 700,000

Principal Payments on Long-Term Debt (2,400,000) (1,150,000)

Proceeds from Stock Options and Warrant Exercises 299,500 1,051,488

Proceeds from Sale of Common Stock 2,119,510 0

Net Cash Provided by Financing Activities 2,803,699 601,488

Net Decrease in Cash and Cash Equivalents (1,456,201) (1,684,591)

Cash & Cash Equivalents at Beginning of Year 2,946,131 4,630,722

Cash & Cash Equivalents at End of Year $ 1,489,930 $ 2,946,131
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F-10

Cash Paid for Interest $ 94,229 138,793

Cash Paid for Taxes $ 800 3,180

Receivable from sale of common stock $ 2,506,023 0

Unrealized Gain on Available-for-Sale Securities, net of tax effect $ 0 $ 3,035

The accompanying notes are an integral part of these financial statements.
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F-11

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” or the 

“Company”) is presented to assist in understanding Royale Energy's financial statements. The financial 

statements and notes are representations of Royale Energy's management, which is responsible for their 

integrity and objectivity. These accounting policies conform to accounting principles generally accepted in 

the United States of America and have been consistently applied in the preparation of the financial 

statements.

Description of Business

Royale Energy is an independent oil and gas producer which also has operations in the area of turnkey 

drilling. Royale Energy owns wells and leases in major geological basins located primarily in California, 

Texas, and Utah. Royale Energy offers fractional working interests and seeks to minimize the risks of oil 

and gas drilling by selling multiple well drilling projects which do not include the use of debt financing.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the 

United States of America requires management to make estimates and assumptions that affect the reported 

amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial 

statements and the reported amounts of revenues and expenses during the reporting period. Actual results 

could differ from those estimates.

Material estimates that are particularly susceptible to significant change relate to the estimate of Company 

oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to 

numerous uncertainties inherent in the estimation of quantities of proven reserves. Estimated reserves are 

used in the calculation of depletion, depreciation and amortization, unevaluated property costs, impairment 

of oil and natural gas properties, estimated future net cash flows, taxes, and contingencies.

Joint Ventures

The accompanying financial statements as of December 31, 2012 and 2011 include the accounts of Royale 

Energy and its proportionate share of the assets, liabilities and results of operations as described in FASB 

ASC 932-323. Royale Energy generally retains an ownership interest of approximately 50% in wells it 

drills with its joint venture projects. Royale Energy is the operator of the majority of properties in which it 

has an ownership interest. In connection with the drilling and operation of wells, the Company receives 

industry standard COPAS fees, which are recorded as supervisory fee income.

Revenue Recognition

Royale Energy recognizes revenues from the sales of oil and natural gas upon transfer of title, net of 

royalties, in the period of delivery. Settlements for oil and natural gas sales can occur up to two months 

after the end of the month in which the oil and natural gas were produced. We estimate and accrue for the 

value of these sales using information available to us at the time our financial statements are generated.

Royale Energy recognizes revenues from the sale of natural gas in which the Company has an interest with 

other producers using the entitlements method of accounting. Under this method we recognize revenue 

based on our entitled ownership percentage of sales of natural gas delivered to purchasers. Gas imbalances 

occur when we sell more or less than our entitled ownership percentage of total natural gas 
Table of Contents

F-12

production. When we receive more than our entitled share, a liability is recorded. Gas imbalances on our 

production at December 31, 2012 and 2011 were not significant.

Upon the sale or retirement of a complete field of a proved property, the Company eliminates the cost from 

its books, and the resultant gain or loss is recorded to Royale Energy’s Statement of Operations. Upon the 

sale of an entire interest in an unproved property where the property has been assessed for impairment 

individually, a gain or loss is recognized in Royale Energy’s Statement of Operations. If a partial interest in 

an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest 

retained. Royale Energy enters into turnkey drilling agreements with investors to develop leasehold acreage 

it has acquired. In these arrangements, Royale Energy acquires a working interest in a prospect pursuant to 

an oil and gas lease, and then sells a portion of a well’s working interest on the acquired lease to investors 

with a turnkey drilling agreement. Title to the lease property is not conveyed to the investor. The investor 

purchases a working interest directly in the well bore. The working interest purchased in the turnkey drilling 

agreements is an ownership interest in which the working interest holder is responsible to bear the cost of 

drilling, testing completing, equipping and operating the well. Royale Energy typically retains 50% of the 

working interest and acts as operator of the projects in which it sells working interests to investors.

In a turnkey drilling agreement, Royale Energy agrees to sell a percentage of the well’s working interest to 

investors and to pay for all costs of identifying, acquiring mineral rights to, drilling, testing, completing and 

equipping the well for initial production at a fixed price. If the actual costs of these activities exceed the 

turnkey price Royale charged to the investors, Royale is responsible to pay the excess cost. If the actual 

costs are less than the turnkey price, Royale retains the excess of the turnkey price over actual costs. Royale 

bears 100% of the risk should actual costs exceed estimated costs of a project for both Royale’s working

interest and the working interest sold to investors in a well. When the well is completed as a commercially 

productive well, Royale Energy and the investors bear the cost of operating the well according to each 

party’s proportionate working interest percentage.

When Royale Energy sponsors a turnkey drilling project for sale, investors enter into a signed contract with 

Royale Energy. In this agreement, the investor agrees to share in the pre-drilling costs, which are nonrefundable, and drilling costs. Pre-drilling costs include geophysical & geographical costs, selling costs, 

spoilage costs, third party broker commission fees, and other costs as required so the drilling of the project 

can proceed. Drilling costs are those costs to lease the mineral rights, build the drilling location, drill, and 

log the well, and if the wells is successful, to complete and test the well. The investment is held and 

reported by Royale Energy as deferred revenue from turnkey drilling. Once drilling begins, it is generally

completed within 10-30 days.

Royale Energy bases the price at which it sells working interests under the turnkey drilling agreement on its 

estimates of the costs, described above, and is based upon the historical cost to complete those 

activities. Revenues covering the pre-drilling and drilling costs are recognized in the period in which a well 

is drilled and logged.

Since the investor’s interest in the prospect is limited to the well, and not the lease, the investor does not 

have a legal right to participate in additional wells drilled within the same lease. However, it is the 

Company’s policy to offer to investors in a successful well the right to participate in subsequent wells at the 

same percentage level as their working interest investment in the prior successful well with similar turnkey 

drilling agreement terms.

If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would 

retain the non-refundable portion of the contact and return the remaining funds to the investors. Included in 

cash and cash equivalents are amounts for use in completion of turnkey drilling programs in progress.
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F-13

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 are charged to expense. Royale Energy makes this determination within one year 

following the completion of drilling. Other exploratory costs are charged to expense as incurred. 

Development costs, including unsuccessful development wells, are capitalized. Depletion, depreciation and 

amortization of oil and gas producing properties are computed on an aggregate basis using the units-ofproduction method.

As required by the Extractive Activities Topic of the Financial Accounting Standards Board (FASB), longlived assets are 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 the Topic is calculated as the difference between the carrying amount of the asset and 

its fair value. Any impairment loss is recorded in the current period in which the recognition criteria are first 

applied and met. Under the successful efforts method of accounting for oil and gas operations, Royale 

Energy periodically assessed its proved properties for impairments by comparing the aggregate net book 

carrying amount of all proved properties with their aggregate future net cash flows. The statement requires 

that the impairment review be performed on the lowest level of asset groupings for which there are 

identifiable cash flows.

Royale Energy performs a periodic review for impairment of proved properties on a field-by-field basis. 

Unamortized capital costs are measured on a field basis and are reduced to fair value if it is determined that 

the sum of expected future net cash flows are less than the net book value. Royale Energy determines if 

impairment has occurred through either adverse changes or as a result of its periodic review for impairment. 

Impairment is measured on a 10% discounted cash flows basis. Impairment losses of $200,778, and 

$4,529,058, were recorded in 2012 and 2011, respectively.

Upon the sale of oil and gas reserves in place, costs and accumulated amortization of such property are 

removed from the accounts and resulting gain or loss on sale is reflected in operations. Impairment of 

unproved properties is assessed periodically on a property-by-property basis, and any impairment in value is 

currently charged to expense. In addition, capitalized costs of unproved properties are assessed periodically 

to determine whether their value has been impaired below the capitalized costs. Loss is recognized to the 

extent that such impairment is indicated. In making these assessments, factors such as exploratory drilling 

results, future drilling plans, and lease expiration terms are considered. When an entire interest in an 

unproved property is sold, gain or loss is recognized, taking into consideration any recorded impairment. 

When a partial interest in an unproved property is sold, funds received are accounted for as a reduction of 

the costs in the interest retained. Upon abandonment of properties, the reserves are deemed fully depleted 

and any unamortized costs are recorded in the statement of operations under impairment expense.

During 2012, impairment losses of $200,778 were recorded in wells or fields where year-end reserve values 

were less than the net book values of wells or where lease and land costs were no longer viable. In 2012, 

one Utah well and two California wells were impaired by $ 11,276 and $ 60,789, respectively. These 

impairments were due to lower proved developed reserves than current book values due to the natural 

declines of the wells. Also in 2012, we recorded lease impairments of $119,322 on various capitalized lease 

and land costs that were no longer viable.

 
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F-14

In 2011, Royale Energy recorded an impairment of $4,516,098 in fields where year-end reserve values no 

longer supported net book values of the related wells in those fields. Royale had impairments in its Lone 

Star and Bowerbank fields in the amounts of $3,776,385, and $28,566, respectively. The impairments were 

the result of natural declines and lower natural gas prices. Additionally, an impairment of $710,124 was 

recognized for our Moon Ridge field in Utah, where recently reduced gas prices and a reevaluation of the 

reservoir significantly lowered proved reserves than originally estimated. Moreover, 2011 impairments also 

include impairments of nonviable geological lease and land costs of $12,959.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and on deposit, and highly liquid debt instruments with 

maturities of three months or less.

Inventory

Inventory consists of well supplies, pipeline and spare parts and is carried at lower of cost or market. During 

2012, we had a write down of $62,744 on certain oil and gas inventory and in 2011 we had a write down of 

$258,043 on certain oil and gas pipeline inventory to its estimated current market value.

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, 2012 and 2011, net accounts receivable was $3,969,160 and $1,872,067 respectively. 

Approximately $2,500,000 of the receivable reported for the year ended 2012 related to the sale of Royale’s 

common stock. The receivable was collected on January 4, 2013. At December 31, 2012 and 2011, the 

Company established an allowance for uncollectable accounts of $934,876 and $671,109, respectively for 

receivables from direct working interest investors whose expenses on non-producing wells were unlikely to 

be collected from revenue.

Equipment and Fixtures

Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which 

range from three to seven years, using the straight-line method. Repairs and maintenance are charged to 

expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are 

removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, 

which neither materially add to the value of the property nor appreciably prolong its life, are charged to 

expense as incurred. Gains or losses on dispositions of property and equipment, other than oil and gas, are 

reflected in operations.
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F-15

Loss Per Share

Basic and diluted losses per share are calculated as follows:

For the Year Ended December 31, 2012

Income

(Numerator)

Shares

(Denominator)

PerShare

Amount

Basic Loss Per Share:

Net loss available to common stock $ (11,961,026) 11,133,377 $ (1.07)

Cumulative effect of accounting change - - -

Diluted Loss Per Share:

Effect of dilutive securities and stock 

options

Net loss available to common stock $ (11,961,026) 11,133,377 $ (1.07)

For the Year Ended December 31, 2011

Income

(Numerator)

Shares

(Denominator)

PerShare

Amount

Basic Loss Per Share:

Net loss available to common stock $ (4,188,241) 10,655,258 $ (0.39)

 Cumulative effect of accounting change - - -

Diluted Loss Per Share:

 Effect of dilutive securities and stock 

options - - -

Net loss available to common stock $ (4,188,241) 10,655,258 $ (0.39)

For the years ended December 31, 2012 and 2011, Royale Energy had dilutive securities of 1,104,314 and 

842,859 respectively. These securities were not included in the dilutive earnings per share due to their antidilutive nature.

Stock Based Compensation

Royale Energy has a stock-based employee compensation plan, which is more fully described in Note 

13. Effective January 1, 2006, the Company adopted the Compensation – Stock Compensation Topic of the 

FASB Accounting Standards Codification, which addresses the accounting for stock-based payment 

transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the 

enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may 

be settled by the issuance of such equity instruments. The Company uses the Black-Scholes option-pricing 

model to determine the fair value of stock-based awards, consistent with that used for pro forma disclosures 

under the Topic.

During the year ended December 31, 2008, the Board of Directors authorized approximately 550,000 shares 

to be issued for equity awards through a stock grant plan adopted in November 2008 and stock option grant 

plan adopted in March 2008.
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F-16

Income Taxes

Royale utilizes the asset and liability approach to measure deferred tax assets and liabilities based on 

temporary differences existing at each balance sheet date using currently enacted tax rates in accordance 

with the Income Taxes Topic of the FASB Accounting Standards Codification. Deferred tax assets and 

liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the 

Topic, deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is 

more likely than not that some portion or all of the deferred tax assets will not be realized.

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 the Fair Value 

Measurements and Disclosures Topic of the FASB Accounting Standards Codification. 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.

Fair Value Measurements

According to Fair Value Measurements and Disclosures Topic of the FASB Accounting Standards 

Codification, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in 

period subsequent to initial recognition, the reporting entity shall disclose information that enable users of its 

financial statements to assess the inputs used to develop those measurements and for recurring fair value 

measurements using significant unobservable inputs, the effect of the measurements on earnings for the 

period.

At December 31, 2011, Royale Energy reported the fair value of $31,027 in available for sale 

securities. The fair value was determined using the number of shares owned as of December 31, 2011, 

multiplied by the market price of those securities on December 31, 2011. These securities were sold during 

the fourth quarter in 2012.

The table below summarizes Royale’s fair value measurements and the level within the fair value hierarchy 

in which the fair value measurements fall. At December 31, 2011, Royale Energy quoted prices in active 

markets for identical assets when determining the fair value measurements at the reporting date.

Description 12/31/2012 Level 1 12/31/2011 Level 1

Available for Sale 

Securities $ 0 $ 0 $ 31,027 $ 31,027

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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F-17

Recently Issued Accounting Pronouncements

The Company has reviewed the updates issued by the Financial Accounting Standards Board (FASB) during 

the year ended December 31, 2012, and have determined that the updates are not applicable to the Company.

NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

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

2012 2011

Oil and Gas

 Producing properties, including intangible 

drilling costs $ 24,327,806 $ 23,684,048

Undeveloped properties 4,034,292 994,687

 Lease and well equipment 9,724,602 10,284,315

38,086,700 34,963,050

 Accumulated depletion, depreciation and 

amortization (27,756,493) (27,553,222)

10,330,207 $ 7,409,828

2012 2011

Commercial and Other

 Real estate, including furniture and 

fixtures $ 502,344 $ 502,344

 Vehicles 151,669 151,669

 Furniture and equipment 1,299,300 1,307,299

1,953,313 1,961,312

 Accumulated depreciation (1,327,723) (1,295,796)

625,590 665,516

$ 10,955,797 8,075,344

The following sets forth costs incurred for oil and gas property acquisition and development activities, 

whether capitalized or expensed:

2012 2011

Acquisition - Proved $ 24,298 145,746

Acquisition- Unproved $ 24,606 33,749

Development $ 577,708 6,493,013

Exploration $ 1,077,001 538,247

The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the 

Extractive Activities Topic of the FASB Accounting Standards Codification requires that we evaluate all 

existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have 

become impaired and are expensed or reclassified during a fiscal period. We did not make any additions to 

capitalized exploratory well costs pending a determination of proved reserves during 2012 or 2011. We did 

not charge any previously capitalized exploratory well costs to expense upon adoption of Topic.
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F-18

12 Months Ended 

December 31,

2012 2011

Beginning balance at January 1 $ 0 $ 0

Additions to capitalized exploratory well 

costs pending the determination of proved 

reserves $ 556,446 $ 0

Reclassifications to wells, facilities, and 

equipment based on the determination of proved 

reserves $ (556,446) $ 0

Ending balance at December 31 $ 0 $ 0

Results of Operations from Oil and Gas Producing and Exploration Activities

The results of operations from oil and gas producing and exploration activities (excluding corporate 

overhead and interest costs) for the two years ended December 31, are as follows:

2012 2011

Oil and gas sales $ 1,673,538 4,879,397

Production related costs (1,139,750 ) (1,517,920)

Lease Impairment (200,778 ) (4,529,058)

Depreciation, depletion and 

amortization (1,448,002 ) (2,362,065)

Results of operations from producing 

and

exploration activities $ (1,114,992) (3,529,646)

Income Taxes (Benefit) 1,831,562 (1,032,831)

Net Results $ (2,946,554) (2,496,815)

NOTE 3 – ASSET RETIREMENT OBLIGATION

The Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards 

Codification 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 Topic apply to legal obligations associated with the retirement of longlived assets that result from the acquisition, development, and operation of a long-lived asset.

2012 2011

Asset retirement obligation Beginning of 

the year $ 575,612 $ 580,568

Liabilities incurred during the period 347,947 21,173
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F-19

Settlements 0 (24,690)

Accretion expense 6,741 9,266

Revisions in estimated cash flow 23,788 (10,705)

Asset retirement obligation End of year $ 954,088 $ 575,612

NOTE 4 - TURNKEY DRILLING CONTRACTS

Royale Energy receives funds under turnkey drilling contracts, which require Royale Energy to drill oil and 

gas wells within a reasonable time period from the date of receipt of the funds. As of December 31, 2012 

and 2011 Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of 

$8,693,743 and $6,909,666, respectively, as a current liability.

NOTE 5 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS

Royale Energy identifies reportable segments by product and country, although Royale Energy currently 

does not have foreign country segments. Royale Energy includes revenues from both external customers and 

revenues from transactions with other operating segments in its measure of segment profit or loss. Royale 

Energy also includes interest revenue and expense, DD&A, and other operating expenses in its measure of 

segment profit or loss.

The accounting policies of the reportable segments are the same as those described in the Summary of 

Significant Accounting Principles (see Note 1).
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F-20

Royale Energy's operations are classified into two principal industry segments. Following is a summary of 

segmented information for 2012 and 2011:

Oil and Gas

Producing

and

Exploration

Turnkey

Drilling

Services Total

Year Ended December 31, 2012

Revenues from External Customers $ 1,673,538 $ 2,028,863 $ 3,702,401

Supervisory Fees 686,261 0 686,261

Interest Revenue 0 6,083 6,083

Interest Expense 97,505 97,504 195,009

Operating Expenses for Segment Assets 4,079,672 3,012,549 7,092,221

Depreciation, Depletion, and Amortization 1,375,602 72,400 1,448,002

Lease Impairment 100,389 100,389 200,778

Gain on Sale of Assets 0 8,100 8,100

Gain on Marketable Securities 7,048 0 7,048

Income Tax Expense 5,398,335 2,036,574 7,434,909

Total Assets 16,628,168 875,167 17,503,335

Net Loss $ (8,684,656) (3,276,370) (11,961,026)

 Year Ended December 31, 2011 

( (restated)

Revenues from External Customers $ 4,879,397 $ 5,794,427 $ 10,673,824

Supervisory Fees 834,372 - 834,372

Interest Revenue - 24,214 24,214

Interest Expense 69,109 69,109 138,218

Operating Expenses for Segment Assets 4,821,462 6,362,117 11,183,579

Depreciation, Depletion, and Amortization 2,243,962 118,103 2, 362,065

Lease Impairment 4,522,578 6,480 4,529,058

Gain on Sale of Assets 759,763 - 759,763

Income Tax (Benefit) (1,516,799) (215,707) (1,732,506)

Total Assets 20,388,197 1,073,063 21,461,260

Net Loss $ (3,666,780) $ (521,461) $ (4,188,241)
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F-21

NOTE 6 - LONG-TERM DEBT

2012 2011

Revolving line of credit secured by oil and gas properties, with a maximum 

available of $14,250,000 at December 31, 2011, issued by Texas Capital 

Bank, N.A. 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 February 13, 

2009. Interest is at Texas Capital Bank’s “Base Rate” plus 1.00% with an 

“Adjusted Base Rate” of 5.00%, resulting in a rate of 5.00% at December 31, 

2012 and 2011, payable monthly with borrowing base reductions of $100,000 

commencing on January 1, 2011. As part of this agreement, Texas Capital 

Bank has issued letters of credit in the amount of $750,000 on behalf of the 

Company to various agencies. At December 31, 2012, Royale’s borrowing 

base with Texas Capital Bank was $350,000. The revolving line of credit 

matured in February 2013. $ 350,000 $ 2,750,000

Note Payable convertible into shares of Royale’s Common stock and a 

Warrant Agreement with certain institutional investors. The Note has a face 

value of $3,333,333.33 and issued with an original issue discount of 10% for 

an aggregate purchase price of $3 million. The Note is not interest bearing 

unless Royale is in default of the Note, in which case the Note carries an 

interest rate of 18% per annum. During each calendar quarter from January 1, 

2013 through December 31, 2013, the holder of the Note intends to require 

Royale to redeem 25% of the original principal amount each 

quarter. Accordingly, the note has been classified as current. Once 

notification is received, Royale, in its sole discretion, may satisfy its 

obligation either in cash or in shares of its common stock. However, at the 

Note’s maturity on December 31, 2014, any outstanding balance on the Note 

is required to be repaid in cash. Note is net of the Discount of Warrant Value 

in the amount of $1,229,354. 1,908,668 -

Total Long Term Debt $ 2,258,668 $ 2,750,000

Less Current Maturity 2,258,668 $ -

Long Term Debt Less Current Portion $ - $ 2,750,000

Significant covenants under the terms of the Texas Capital Bank, Inc. line of credit agreement include that 

the Company will have a tangible net worth not less than $5,424,014 as of December 31, 2008, plus 75% of 

positive quarterly net income thereafter, an interest coverage ratio not less than 3.00:1, and a bank defined 

current ratio not less than 1:1. The Company was not in compliance with the terms of this agreement at 

December 31, 2012, but has obtained a waiver from Texas Capital Bank, Inc. In June 2009, a joint and 

several guarantee of the $750,000 Letter of Credit Facility by and between Stephen Hosmer and Harry 

Hosmer was added the loan agreement. Guarantors will be required to collectively maintain unencumbered 

liquidity in the form of cash or marketable securities equal to 150% of the line amount.

The Warrant Agreement entitles the holder to purchase, in whole or in part, an aggregate of 500,000 shares 

of Royale’s Common stock at an initial exercise price of $3.00 per share. The warrant has a three year term 

and becomes exercisable on April 29, 2013. The value of the warrant was determined using the BlackScholes pricing method utilizing a strike price of $3.00, 3 year maturity, a risk free interest of 0.8805%, and 

expected volatility of 107.7%. Based upon these inputs, the value of each warrant share was calculated to be 

$1.9536.
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F-22

In addition to the Note and Warrant Agreement, Royale also agreed to (i) not issue any securities for each 

period commencing on the date of receipt of an optional redemption notice and ending 20 trading days 

following the redemption required by such optional redemption notice, subject to certain limited exceptions, 

(ii) not to enter into a variable rate transaction at any time until the earlier of two years from the closing date 

or the date on which none of the Notes or Warrants are outstanding, and (iii) to allow the investors to 

participate in future issuances of securities, subject to certain exceptions, for a period of one year from the 

date hereof. In addition, we have agreed to hold a shareholders’ meeting no later than June 30, 2013, to 

approve: (A) an amendment of our Articles of Incorporation to increase the Company’s authorized capital 

stock to 51,000,000 shares, including 50,000,000 shares of common stock and 1,000,000 shares of preferred 

stock; and (B) making the exchange cap in the Notes and the floor price on the exercise price of the 

Warrants inapplicable with respect to issuances of common stock in excess of the exchange cap in the Notes 

and below the floor price in the Warrants in accordance with Nasdaq rules.

NOTE 7 - INCOME TAXES

Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying 

amount of assets and liabilities for financial reporting purposes and amounts used for income tax 

purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it 

is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax 

assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

Significant components of the Company’s deferred assets and liabilities at December 31, 2012 and 2011, 

respectively, are as follows:

2012 2011

Deferred Tax Assets (Liabilities):

 Statutory Depletion Carry Forward $ 776,534 $ 839,572

 Net Operating Loss 4,951,344 2,860,706

 Other 212,798 375,881

 Share-Based Compensation 58,558 42,321

 Mark to Market Securities - (1,240)

 Capital Loss / AMT Credit Carry 

Forward 76,410 76,410

 Charitable Contributions Carry 

Forward 16,022 14,416

Allowance for Doubtful Accounts 372,772 263,966

Oil and Gas Properties and Fixed 

Assets 3,711,789 3,799,419

$ 10,176,227 $ 8,271,451

Valuation Allowance (10,176,227) (839,572)

Net Deferred Tax Asset $ - $ 7,431,879

Deferred Tax Assets:

 Current $ 107,563 $ 661,645

 Non-current (107,563) 6,771,474

Deferred Tax Liabilities:

 Current (1,240)

Non-current -

Net Deferred Tax Asset $ - $ 7,431,879
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F-23

At the end of 2012, management reviewed the realizability of the Company’s net deferred tax assets. Due 

to the Company’s cumulative losses in recent years, and its inability to conclude a transaction concerning its 

Alaska acreage by the end of 2012, Royale and its management concluded that it is not “more-likely-thannot” its deferred tax assets will be realized. As a result, the Company recorded a full valuation allowance 

against the net deferred tax assets in 2012. The Company will assess the realizability of the deferred tax 

assets at least yearly and make appropriate updates as needed. The Company had statutory percentage 

depletion carry forwards of approximately $1,900,000 at December 31, 2012. The depletion has no 

expiration date. The Company also has a net operating loss carry forward of approximately $10,900,000 at 

December 31, 2012, which will begin to expire in 2027.

A reconciliation of Royale Energy's provision for income taxes and the amount computed by applying the 

statutory income tax rates at December 31, 2012 and 2011, respectively, to pretax income is as follows:

2012 2011

Tax (benefit) computed at statutory rate 

of 34% $ (1,538,880) $ (2,013,054)

Increase (decrease) in taxes resulting 

from:

 State tax / percentage depletion / other 1,128,788 (263,772)

 Other non-deductible expenses 2,888 2,942

Change in valuation allowance 7,842,113 541,378

Provision (benefit) $ 7,434,909 $ (1,732,506)

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

2012 2011

Current tax provision (benefit) – federal $ - -

Current tax provision (benefit) – state 1,790 3,090

Deferred tax provision (benefit) –

federal 6,265,479 (1,409,034)

Deferred tax provision (benefit) – state 1,167,640 (326,562)

Total provision (benefit) $ 7,434,909 (1,732,506)

In January 2007, Royale adopted additional provisions from the Income Taxes Topic of the FASB 

Accounting Standards Codification, which clarified the accounting for uncertainty in income taxes 

recognized in an entity’s financial statements and prescribes a recognition threshold and measurement 

attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. As 

a result of our implementation of the Topic at the time of adoption and at December 31, 2012, the Company 

did not recognize a liability for uncertain tax positions. Currently, the only differences between our 

financial statements and our income tax returns relate to normal timing differences such as depreciation, 

depletion and amortization, which are recorded as deferred taxes on our consolidated balance sheets. We do 

not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 

2009 through 2011 remain open to examination by the taxing jurisdictions in which we file income tax 

returns.

NOTE 8 - 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 
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F-24

not have the right of redemption at the stockholders' option. During the years ending December 31, 2012, 

and 2011, there were no conversions of Series AA Preferred stock, and as of December 31, 2012, and 2011 

there were 52,784 shares of Series AA Preferred stock issued and outstanding.

NOTE 9 - COMMON STOCK

In February 2012, Royale Energy entered into a Sales Agreement with C. K. Cooper & Company, Inc. 

(“CKCC”), under which the Company may issue and sell shares of its common stock for consideration of up 

to $10,000,000, from time to time in an at the market equity offering program with CKCC acting as the 

Company’s sales agent (the “Offering”). Sales of common stock if any, under the program will depend 

upon market conditions and other factors to be determined by the Company and may be made in negotiated 

transactions or transactions that are deemed to be “at the market offerings” as defined in Rule 415 under the 

Securities Act of 1933, as amended, including sales made directly on the NASDAQ Capital Market, on any 

other existing trading market for the common stock or through a market maker. The Company has no 

obligation to sell any common shares in the program and may at any time suspend solicitation and offers 

under the program or terminate the program. The Company will pay CKCC a commission equal to 3.5% of 

the gross sales price of any such shares sold, through it as sales agent, as set forth in the Sales Agreement. 

The Company has also agreed to reimburse CKCC for certain expenses incurred in connection with entering 

into the Sales Agreement and has provided CKCC with customary indemnification rights.

In June 2008, Royale Energy entered into a Securities Purchase Agreement with Cranshire Capital, L.P. to 

issue and sell 547,945 shares of its common stock in exchange for approximately $4,000,000 (i.e. $7.30 per 

share). As part of the agreement, Cranshire was also issued a warrant to acquire additional shares of its 

common stock. The warrant, which expires on June 10, 2013, is exercisable for an aggregate of 191,781 

shares at an exercise price of $7.30 per share. The $7.30 per share price was negotiated as a 15% discount 

from the 10 day dollar volume weighted average price of the Company’s Common Stock on the NASDAQ 

Global Market. In conjunction with the August 2009 agreement (see below) the price of these share were 

adjusted to an exercise price of $1.99 per share. In March 2011, warrants were exercised for 71,918 shares 

of the Company’s common stock for approximately $143,117 ($1.99 per share). The net proceeds from the 

private placement and warrant exercise went towards general corporate purposes, including the acquisition 

of oil and natural gas properties for future development.

On August 4, 2009, Royale Energy, Inc., entered into a Securities Purchase Agreement with Cranshire 

Capital, L.P. The terms of the agreement include the sale of 552,764 shares of common stock at $1.99 per 

share. The warrants include: (i) Series A Warrants, which are immediately exercisable for a period of 5 

years into 329,850 shares at $2.19 per share; (ii) Series A-1 Warrants, which are exercisable beginning 

February 6, 2010 for a period of 5 years into 1,808 shares at $2.19 per share, (iii) Series B Warrants, which 

are immediately exercisable for a period of up to 1 year into 511,628 shares at $2.15 per share and (iv) 

Series C Warrants, which are immediately exercisable for a period of 5 years into 306,977 shares at $2.19 

per share but only to the extent that the Series B Warrants are exercised and only in the same percentage that 

the Series B Warrants are exercised. All of such warrants contain customary adjustments for corporate 

events such as reorganizations, splits, dividends, and the exercise prices of all such warrants are subject to 

weighted-average anti-dilution adjustments in the event of additional issuances of common stock below the 

exercise price then in effect. The exercise price of the Series B Warrants is also subject to increases if the 

market price of the common stock equals or exceeds $2.40, in which case the exercise price of such Series B 

warrant will be increased to 90% of the closing sale price of the common stock on the trading day 

immediately preceding the date of exercise thereof. The Company will also provide customary registration 

rights in connection with the transaction. In September and October 2009, the Series B warrants were 

exercised for 511,628 shares of Royale Energy common stock. The net proceeds received for the shares, 

$1,080,650, were used for general working capital purposes. During March and April 2011, the Series A 

warrants were exercised for 329,850 shares of Royale Energy common stock. The net proceeds received for 

the shares, approximately $722,372, were used for general working capital purposes. During February and 

March 2011, in a separate exercise, warrants were exercised for 67,160 of the Company’s common 

stock. The net proceeds of approximately $185,999 were used for general working capital purposes.
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F-25

NOTE 10 - 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 and yard in Woodland, CA. The San Diego lease is under a 120 month noncancellable 

lease contract, which expires in July 2015. The San Diego lease calls for monthly payments ranging from 

$27,010 to $35,271, and the Woodland lease calls for monthly payments of $900. Future minimum lease 

obligations as of December 31, 2012 are as follows:

Year Ended

December 31,

2013 $ 403,873

2014 $ 415,842

2015 $ 246,900

Thereafter $ -

Total $ 1,066,615

Rental expense for the years ended December 31, 2012 and 2011 was $ 370,750 and $371,520 respectively.

NOTE 11 - RELATED PARTY TRANSACTIONS

Significant Ownership Interests

Donald H. Hosmer, Royale Energy’s co-president and co-chief executive officer owns 8.59% 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 co-president, co-chief executive officer and chief financial officer, 

owns 11.64% 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 6.28% 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 $3,451 and 

$23,010 for their interests for the years ended December 31, 2012 and 2011, respectively.

NOTE 12 - STOCK COMPENSATION PLAN

During the Board of Directors meeting held in December 2010, directors and executive officers of Royale 

Energy were each granted 50,000 stock options, a total of 400,000 options, to purchase common stock at an 

exercise or base price of $3.25 per share. These options are to vest in two parts; the first 200,000 options 

vested on January 1, 2011; the remaining 200,000 options vested on January 1, 2012. The options were 

granted with a legal life of five years, and a service period of two years beginning January 1, 2011. During 

2012 and 2011, Royale recognized compensation costs of $39,260 and $40,015, respectively and a tax 

expense of $38,652 and tax benefit of $11,611, respectively relating to this option grant.
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F-26

The fair value of the options was calculated using the Black-Scholes option pricing method. Since, at the 

time of option grant, there was currently no market for options of Royale’s common stock, expected 

volatilities are based on historical volatility of the Company’s stock and other factors. Royale Energy uses 

historical data to estimate option exercise and board member turnover within the valuation model. The riskfree rate for the periods within the contractual life of the option is based on the U.S. Treasury yield curve in 

effect at the time of the grant.

A summary of the status of Royale Energy's stock option plan as of December 31, 2012 and 2011, and 

changes during the years ending on those dates is presented below:

2012 2011

Weighted- WeightedAverage Average

Exercise Exercise

Shares Price Shares Price

Options

 Outstanding at Beginning of Year 675,000 $ 3.36 320,000 $ 3.50

 Granted - $ 400,000 3.25

 Exercised (283,692) $ 3.46 (45,000) 3.44

 Expired or Ineligible (45,000) 3.50 -

 Outstanding at End of Year 346,308 $ 3.25 675,000 $ 3.36

 Options Exercisable at Year End 346,308 $ 3.25 475,000 $ 3.40

Weighted-average Fair Value of Options

 Granted During the Year $ - - $ 0.21

The weighted-average grant-date fair value of options granted during 2011 was $0.21 per share, and the fair 

value of the options vested in 2011 was $40,015. The total intrinsic value of options exercised during 2011 

was $112,050. At December 31, 2011, Royale’s stock price was $4.58 creating an intrinsic value of 

$823,500 and $560,500 for the options outstanding and exercisable at year end, respectively. At December 

31, 2012, Royale Energy’s stock price, $2.58, was less than the weighted average exercise price, and as such 

the outstanding and exercisable stock options had no intrinsic value. These stock options have a weightedaverage remaining contractual term of 3 years as of December 31, 2012. There were no new stock options 

granted during 2012.

In November 2008, the Board of Directors granted the directors and executive officers of Royale Energy 

95,000 shares of restricted common stock. The number of granted shares will double to 190,000 shares of 

common stock if Royale’s stock price reaches $15 a share during the period. The grant is to be vested in 

three parts. Each part of 31,665 shares vested on November 30, 2009, 2010, and 2011. Royale recognized 

share-based compensation of $67,583 and $19,610 as a tax benefit for this stock grant in the year ended 

December 31, 2011.
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F-27

A summary of the status of Royale Energy's restricted stock grant plans as of December 31, 2012 and 2011, 

and changes during the years ending on those dates is presented below:

2012 2011

Weighted- WeightedAverage Average

Grant-Date Grant-Date

Shares Fair Value Shares Fair Value

Non-vested Shares

 Non-vested at Beginning of Year - $ - 31,670 $ 3.31

 Granted - -

 Reinstated - -

 Vested - 31,670 $ 3.31

 Expired or Ineligible - $ -

 Non-vested at End of Year - - $ 3.31

NOTE 13 - 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, 2012 and 2011, were $57,405, and $60,366 

respectively.

NOTE 14 - 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 2012 or 2011.

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 15 - CONCENTRATIONS OF CREDIT RISK

The Company bids its gas sales on a month to month basis and generally sells to a single customer without 

commitment to future gas sales to any particular customer. The Company normally sells approximately 83% 

of its monthly natural gas production to one customer on a month to month basis. Since we are able to sell 

our natural gas to other readily available customers, the loss of any one customer would not have an adverse 

effect on our overall sales operations.

The Company maintains cash in depository institutions that are guaranteed by the Federal Deposit Insurance 

Corporation (FDIC) up to $250,000 per institution for our interest bearing accounts in the years ended 

December 31, 2012, and 2011. At December 31, 2012, and 2011, the Company’s non-interest bearing 

accounts were fully insured by the FDIC. At December 31, 2012 and 2011, cash in banks exceeded the 

FDIC limits by approximately $1.2 million and $2.4 million, respectively. The Company has not 

experienced any losses on deposits.
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F-28

NOTE 16 - COMMITMENTS AND CONTINGENCIES

The Company may become involved from time to time in litigation on various matters, which are routine to 

the conduct of its business. The Company believes that none of these actions, individually or in the 

aggregate, will have a material adverse effect on its financial position or results of operations, though any 

adverse decision in these cases or the costs of defending or settling such claims could have a material effect 

on its business.

National Fuel Corporation (“NFC”) v. Royale Energy, Inc., No. 080800735, Uintah County, Utah. NFC 

filed this lawsuit seeking to remove Royale as operator of the property in which Royale is the 75% record 

owner and operator and NFC was a non-operator with a 25% ownership. Trial was held on October 18-21, 

2011, at which Royale defended itself vigorously. On February 2, 2012, the Court issued its ruling, denying 

NFC’s request to remove Royale as operator. On April 6, 2012, judgment pursuant to the ruling was 

entered, and NFC filed an appeal. Effective February 1, 2013, during the pendency of the appeal, the case 

was settled. We anticipate that the appeal will be dismissed shortly, and the litigation concluded. There was 

no cash paid out as a result of the ruling.

Douglas Jones v. Royale Energy, Inc., et.al.

On July 1, 2010, Douglas Jones filed a lawsuit against the Company in the Circuit Court, 17th Judicial 

District, Broward County, Florida. Mr. Jones was an independent contractor handling certain aspects of 

sales for the Company prior to July 2, 2008. He asserts that he is entitled to an unspecified amount for 

commissions and expenses. The Company denies that any money is owed to Mr. Jones, and intends to 

defend the lawsuit vigorously. On August 16, 2010, the Company, through Florida counsel Adam Hodkin, 

filed a motion to dismiss the lawsuit for lack of jurisdiction in the Florida courts. The Court has set the 

motion to dismiss for hearing on March 15, 2012, but the hearing was taken off calendar at the request of the 

plaintiff, Mr. Jones. The court then reset the motion for hearing on February 27, 2013. At the hearing, the 

judge took the matter under submission to consider whether he needed to hold an evidentiary hearing or 

whether he could rule on the papers. If the motion to dismiss is denied, Royale intends to answer their 

complaint and oppose the lawsuit vigorously.

NOTE 17 - SUBSEQUENT EVENTS

On January 2, 2013 and on April 4, 2013, Royale’s convertible note holders exercised their put option to 

redeem 25% of the original principal amount. Royale paid $854,167, which included a 2.5% premium 

because the obligation was met in cash, on January 7, 2013, and issued 479,589 of its common stock on 

April 5, 2013 to satisfy each notice to redeem 25% of the original principal amount. As of April 15, 2013, 

Royale has an outstanding balance of approximately $1,666,667 related to the convertible notes.
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F-29

NOTE 18 – RESTATEMENT TO REFLECT CHANGE IN REVENUE RECOGNITION POLICY

The Company has restated its previously issued 2011 financial statements for the correction of an error in 

the method of revenue recognition. The effect on the Company’s issued 2011 financial statements is 

summarized below:

As 

Previously

Reported As Restated

Balance sheet as of December 31, 2010:

Accumulated deficit (16,807,424) (18,037,663)

Balance sheet as of December 31, 2011:

Deferred Tax Asset 6,055,803 6,771,474

Total Assets 20,745,589 21,461,260

Deferred Revenue from Turnkey Drilling 4,879,853 6,909,666

Total Current Liabilities 9,423,834 11,453,647

Total Liabilities 12,749,446 14,779,259

Accumulated Deficit 20,911,762 22,225,904

Total paid in capital and accumulated deficit 7,543,515 6,861,377

Total Stockholder’s Equity 7,996,143 6,682,001

Total Liabilities and Stockholder’s Equity 20,745,589 21,461,260

Statement of Operations for the year ended 

December 31, 2011:

Turnkey Drilling 5,933,065 5,794,427

Total Revenues 11,671,048 11,532,410

Income From Operations (5,643,891) (5,782,529)

Income Before Income Tax Expense (5,782,109) (5,920,747)

Income Tax Provision (Benefit) (1,677,771) (1,732,506)

Net Income (Loss) (4,104,338) (4,188,241)

Comprehensive Income (Loss) (4,101,303) (4,185,206)
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F-30

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 which are 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 petroleum 

engineering consultants Netherland, Sewell & Associates, Inc. and Source Energy, LLC, the net reserve 

value of its proved developed and undeveloped reserves was approximately $7.6 million at December 31, 

2012, based on natural gas prices ranging from $2.59 per MCF to $3.09 per MCF as applied on a field-byfield basis. Source Energy, LLC supplied reserve value estimates for Royale Energy’s Utah properties, and 

Netherland, Sewell & Associates, Inc. provided reserve information for the Company’s California, Texas, 

Oklahoma, and Louisiana properties. 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.

The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, 

Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and 

confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves 

Information promulgated by the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a 

firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an 

interest in our properties and are not employed on a contingent basis. All activities and reports performed 

and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are 

managed and reviewed by Royale’s Chief Geologist and Vice President of Exploration. This person earned 

a Ph.D. in geosciences from the University of Sheffield, England, and has over 30 years of experience in the 

petroleum exploration industry. After our Chief Geologist and Vice President of Exploration completes his 

review and analysis of the estimates from Netherland, Sewell & Associates, the estimates are reviewed again 

by Royale’s Co-CEO, Co-President, and CFO.

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.
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F-31

Changes in Estimated Reserve Quantities

The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at 

December 31, 2012 and 2011 and changes in such quantities during each of the years then ended, were as 

follows:

2012 2011

Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF)

Proved developed and undeveloped reserves:

Beginning of period 4,900 4,569,850 16,830 5,733,873

Revisions of previous estimates (2,658) (436,443) 2,205 (1,044,000)

Production (1,558) (559,590) (2,264) (1,144,469)

Extensions, discoveries and improved recovery 63,200 892,990 1,024,446

Purchase of minerals in place 16 31,162

Sales of minerals in place (11,871)

Proved reserves end of period 63,900 4,497,970 4,900 4,569,850

2012 2011

Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF)

Proved developed reserves:

Beginning of period 4,900 4,174,050 16,830 5,041,179

End of period 700 3,188,390 4,900 4,174,050

2012 2011

Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF)

Proved undeveloped reserves:

Beginning of period - 395,800 - 692,694

End of period 63,200 1,309,580 - 395,800

For December 31, 2012, natural gas extensions, discoveries and improved recovery amounted to 892,990 

MCF which was mainly the result of drilling one new exploratory well in 2012, which consisted of 856,030 

MCF of proved undeveloped reserves. Another location, carried over from December 31, 2011, which was 

not drilled in 2012, was revised upward to 416,590 MCF in proved undeveloped reserves at year end 

2012. Additionally in 2012, oil extensions, discoveries and improved recovery came to 63,200 BBL which 

was due to four new locations, on previously owned leases, which during 2012 were proven by new outside 

development in the area. Each of the four locations has approximately 15,800 BBL and 9,240 MCF of 

proved undeveloped reserves. A location which had 347,000 MCF in proved developed reserves at 

December 31, 2011, was drilled and began producing in 2011, was revised downward 306,837 MCF at 

December 31, 2012. An additional location, which was also drilled and began producing in 2011, had 

proved developed reserves of 379,300 at December 31, 2011, revised downward 126,653 MCF at December 

31, 2012.
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F-32

For December 31, 2011, extensions, discoveries and improved recovery came to 1,024,446 MCF which was 

added as a result of drilling three new developmental wells in 2011. These consisted of 127,846 MCF of 

proved developed producing reserves on one location and 896,600 MCF of proved developed non-producing 

reserves on three locations. Another location which had 300,683 MCF in proved undeveloped reserves at 

December 31, 2010, was drilled and began producing in 2011, was revised downward 270,560 MCF at 

December 31, 2011. Another location, carried over from December 31, 2010, was not drilled in 2011, has 

395,800 MCF in proved undeveloped reserves.

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, 2012.

The future net cash inflows are developed as follows:

• Estimates are made of quantities of proved reserves and the future periods during which they are 

expected to be produced based on year-end economic conditions.

• The estimated future production of proved reserves is priced on the basis of year-end prices.

• The resulting future gross revenue streams are reduced by estimated future costs to develop and to 

produce proved reserves, based on year-end estimates. Estimated future development costs by year 

are as follows:

2013 $ 2,311,210

2014 1,455,100

2015 22,000

Thereafter 167,200

Total $ 3,955,510

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 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.
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F-33

2012 2011

Future cash inflows $ 18,248,440 19.133,280

Future production costs (6,661,330) (7,698,630)

Future development costs (3,955,510) (1,181,010)

Future income tax expense (2,289,480) (3,076,065)

Future net cash flows 5,342,120 7,177,575

10% annual discount for estimated timing of cash flows (1,404,499) (1,619,267)

Standardized measure of discounted future net cash flows $ 3,937,621 5,558,308

Sales of oil and gas produced, net of production costs $ (344,130) (1,130,540)

Revisions of previous quantity estimates (2,813,520) (4,115,420)

Net changes in prices and production costs (1,158,708) (1,068,429)

Sales of minerals in place - (307,644)

Purchases of minerals in place - -

Extensions, discoveries and improved recovery 1,480,350 1,459,973

Accretion of discount 520,741 688,468

Net change in income tax 694,580 1,342,077

Net decrease $ (1,620,687) (3,131,515)

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 2013 through 2015.

Future development cost of: 2013 2014 2015

Proved developed reserves $ 14,010 $ - $ -

Proved non-producing reserves 57,100 55,100 22,000

Proved undeveloped reserves 2,240,100 1,400,000 -

Total $ 2,311,210 $ 1,455,100 $ 22,000

Common assumptions include such matters as the real extent and average thickness of a particular reservoir, 

the average porosity and permeability of the reservoir, the anticipated future production from existing and 

future wells, future development and production costs and the ultimate hydrocarbon recovery 

percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently 

revised in subsequent periods to reflect production data obtained after the date of the original estimate. If 

the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future 

production revenues may be less than estimated.

Additional data relating to Royale Energy's oil and natural gas properties is disclosed in Supplemental 

Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy's Financial 

Statements, beginning on page F-1
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F-34

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:

2012 $ 0

2011 $ 1,560,735

2010 $ 0
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F-35

Exhibit 23.1

Consent of Independent

Registered Public Accounting Firm

We consent to the incorporation by reference in Registration Statement (No. 333-163184) filed November 

18, 2009 on Form S-3 of Royale Energy, Inc. of our report dated April 15, 2013, relating to our audits of the 

financial statements, which appear in the Annual Report on Form 10-K of Royale Energy, Inc. as of 

December 31, 2012 and 2011, and for the years then ended.

We also consent to the reference to our firm under the captions “Experts” in the Prospectus, which is part of 

the Registration Statement.

/s/ Padgett, Stratemann & Co., L.L.P.

Padgett, Stratemann & Co., L.L.P.

San Antonio, Texas

April 15, 2013
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F-36

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion of our report of Royale Energy (the “Company”) dated April 3, 2013, in 

the Annual Report on Form 10-K for the year ended December 31, 2012, of the Company and its 

subsidiaries, to be filed with the Securities and Exchange Commission.

We also consent to the reference to our firm under the captions “Experts” in the Prospectus, which is part of 

the Registration Statement.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By: /s/ Danny D. Simmons 

Danny D. Simmons, P.E.

President and Chief Operating Officer

Houston, Texas

April 15, 2013

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & 

Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be 

substantively the same as the original signed document maintained by NSAI. The digital document is 

subject to the parameters, limitations, and conditions stated in the original document. In the event of any 

differences between the digital document and the original document, the original document shall control and 

supersede the digital document.
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F-37

Exhibit 23.3

Source Energy Corp.

3555 Santoro Way, Suite A

San Diego, CA 92130

Phone (858) 259-2271

Fax (858) 259-2273

April 15, 2013

Mr. Stephen Hosmer

Royale Energy Inc.

7676 Hazard Center Drive, Suite 1500

San Diego, CA 92108

Dear Mr. Hosmer:

We hereby consent to the incorporation by reference in the registration statement (No. 333-163184) on Form 

S-3 of Royale Energy, Inc. (the “Company”) of the reference to Source Energy Corp. and the inclusion of 

our report dated February 14, 2013, in the Annual Report on Form 10-K for the year ended December 31, 

2012, of the Company, filed with the Securities and Exchange Commission.

We also consent to the reference to our firm under the captions "Experts" in the Prospectus, which is part of 

this Registration Statement.

Source Energy Corp

By: /s/ James Frimodig

Title: President
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F-38

Exhibit 31.1

I, Donald H. Hosmer, certify that:

1. I have reviewed this report on Form 10-K of Royale Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to 

state a material fact necessary to make the statements made, in light of the circumstances under which such 

statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, 

fairly present in all material respects the financial condition, results of operations and cash flows of the 

registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure 

controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control 

over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and 

have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and 

procedures to be designed under our supervision, to ensure that material information relating to the 

registrant, including its consolidated subsidiaries, is made known to us by others within those entities, 

particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over 

financial reporting to be designed under our supervision, to provide reasonable assurance regarding the 

reliability of financial reporting and the preparation of financial statements for external purposes in 

accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in 

this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of 

the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that 

occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal in the case of an 

annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s 

internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of 

internal control over financial reporting, to the registrant's auditors and the audit committee of the 

registrant's board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control 

over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, 

process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a 

significant role in the registrant's internal control over financial reporting.

Date: April 30, 2013 /s/ Donald H. Hosmer

Donald H. Hosmer, Co-President and Co-Chief Executive Officer

Exhibit 31.2
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F-39

I, Stephen M. Hosmer, certify that:

1. I have reviewed this report on Form 10-K of Royale Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to 

state a material fact necessary to make the statements made, in light of the circumstances under which such 

statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, 

fairly present in all material respects the financial condition, results of operations and cash flows of the 

registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure 

controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control 

over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and 

have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and 

procedures to be designed under our supervision, to ensure that material information relating to the

registrant, including its consolidated subsidiaries, is made known to us by others within those entities, 

particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over 

financial reporting to be designed under our supervision, to provide reasonable assurance regarding the 

reliability of financial reporting and the preparation of financial statements for external purposes in 

accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in 

this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of 

the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that 

occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal in the case of an 

annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s 

internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of 

internal control over financial reporting, to the registrant's auditors and the audit committee of the 

registrant's board of directors (or persons performing the equivalent functions)

a) all significant deficiencies and material weaknesses in the design or operation of internal control 

over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, 

process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a 

significant role in the registrant's internal control over financial reporting.

Date: April 30, 2013 /s/ Stephen M. Hosmer

Stephen M. Hosmer, Co-President, Co-Chief Executive Officer and Chief 

Financial Officer
Table of Contents

F-40

Exhibit 32.1

Certification Pursuant to 18 U.S.C. § 1350

The undersigned, Donald H. Hosmer, Co-President and Co-Chief Executive Officer of Royale Energy, Inc., 

a California corporation (the "Company"), pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 

of the Sarbanes Oxley Act of 2002, hereby certifies that:

(1) the Company's Quarterly Report on Form 10-K for the period ended December 31, 2012 (the "Report") 

fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition 

and results of operations of the Company.

Date: April 30, 2013 By: /s/ Donald H. Hosmer

Donald H. Hosmer, Co-President and Co-Chief Executive Officer
Table of Contents

F-41

Exhibit 32.2

Certification Pursuant to 18 U.S.C. § 1350

The undersigned, Stephen M. Hosmer, Co-President, Co-Chief Executive Officer and Chief Financial 

Officer of Royale Energy, Inc., a California corporation (the "Company"), pursuant to 18 U.S.C. 1350, as 

adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, hereby certifies that:

(1) the Company's Annual Report on Form 10-K for the period ended December 31, 2012 (the "Report") 

fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition 

and results of operations of the Company.

Date: April 30, 2013 By: /s/ Stephen M. Hosmer

Stephen M. Hosmer, Co-President, Co-Chief Executive Officer and 

Chief Financial Officer
Table of Contents

F-42

Exhibit 99.1

April 3, 2013

Mr. Stephen Hosmer

Royale Energy, Inc.

7676 Hazard Center Drive, Suite 1500

San Diego, California 92108

Dear Mr. Hosmer:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 

31, 2012, to the Royale Energy, Inc. (Royale) interest in certain oil and gas properties located in California, 

Louisiana, Oklahoma, and Texas. We completed our evaluation on or about February 11, 2013. It is our 

understanding that the proved reserves estimated in this report constitute approximately 90 percent of all 

proved reserves owned by Royale. The estimates in this report have been prepared in accordance with the 

definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception 

of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 

932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This 

report has been prepared for Royale's use in filing with the SEC; in our opinion the assumptions, data, 

methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Royale interest in these properties, as of 

December 31, 2012, to be:

Net Reserves Future Net Revenue (M$)

Oil Gas

Present 

Worth

Category (MBBL) (MMCF) Total at 10%

Proved Developed Producing 0.7 796.1 856.2 720.6

Proved Developed Non-Producing 0.0 1,914.5 3,406.8 2,063.6

Proved Undeveloped 63.2 1,309.6 2,493.3 1,684.1

Total Proved 63.9 4,020.2 6,756.3 4,468.4

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels 

(MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic 

feet (MMCF) at standard temperature and pressure bases.
F-43

The estimates shown in this report are for proved reserves. No study was made to determine whether 

probable or possible reserves might be established for these properties. This report does not include any 

value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped 

reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves 

subcategorization is based on development and production status. The estimates of reserves and future 

revenue included herein have not been adjusted for risk.

Gross revenue is Royale's share of the gross (100 percent) revenue from the properties prior to any 

deductions. Future net revenue is after deductions for Royale's share of production taxes, ad valorem taxes, 

capital costs, and operating expenses but before consideration of any income taxes. The future net revenue 

has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to 

indicate the effect of time on the value of money. Future net revenue presented in this report, whether 

discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-themonth price for each month in the period January through December 2012. For oil volumes, the average 

West Texas Intermediate posted price of $91.21 per barrel is adjusted by lease for quality, transportation 

fees, and regional price differentials. For gas volumes, the average PG&E city-gate spot price of $3.088 per 

MMBTU is used for the California properties and the average Henry Hub spot price of $2.757 per MMBTU 

is used for all other properties. Gas prices are adjusted by lease for energy content, transportation fees, and 

regional price differentials. All prices are held constant throughout the lives of the properties. The average 

adjusted product prices weighted by production over the remaining lives of the properties are $84.91 per 

barrel of oil and $2.882 per MCF of gas.

Operating costs used in this report are based on operating expense records of Royale. For nonoperated 

properties, these costs include the per-well overhead expenses allowed under joint operating agreements 

along with estimates of costs to be incurred at and below the district and field levels. As requested, 

operating costs for the operated properties are limited to direct lease- and field-level costs and Royale's 

estimate of the portion of its headquarters general and administrative overhead expenses necessary to 

operate the properties. Operating costs are held constant throughout the lives of the properties.

Capital costs used in this report were provided by Royale and are based on authorizations for expenditure 

and actual costs from recent activity. Capital costs are included as required for workovers, new 

development wells, and production equipment. Based on our understanding of future development plans, a 

review of the records provided to us, and our knowledge of similar properties, we regard these estimated 

capital costs to be reasonable. Our estimates do not include any salvage value for the lease and well 

equipment or the cost of abandoning the properties. It is our understanding that Royale has fully prefunded 

accounts that meet or exceed its estimates of abandonment costs for the properties, net of any salvage value.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we 

examine the mechanical operation or condition of the wells and facilities. We have not investigated possible 

environmental liability related to the properties; therefore, our estimates do not include any costs due to such 

possible liability.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or 

underdelivery to the Royale interest. Therefore, our estimates of reserves and future revenue do not include 

adjustments for the settlement of any such imbalances; our projections are based on Royale receiving its net 

revenue interest share of estimated future gross gas production.
F-44

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved

reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be 

estimated with reasonable certainty to be economically producible; probable and possible reserves are those 

additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of 

reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, 

or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our 

estimates are based on certain assumptions including, but not limited to, that the properties will be 

developed consistent with current development plans, that the properties will be operated in a prudent 

manner, that no governmental regulations or controls will be put in place that would impact the ability of the 

interest owner to recover the reserves, and that our projections of future production will prove consistent 

with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto 

could be more or less than the estimated amounts. Because of governmental policies and uncertainties of 

supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such 

reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, 

geologic maps, seismic data, well test data, production data, historical price and cost information, and 

property ownership interests. The reserves in this report have been estimated using deterministic methods; 

these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and 

Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE 

Standards). We used standard engineering and geoscience methods, or a combination of methods, including 

performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary 

to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial 

portion of these reserves are for behind-pipe zones and undeveloped locations; such reserves are based on 

estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar 

geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties 

inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily 

represent only informed professional judgment.
F-45

The data used in our estimates were obtained from Royale, public data sources, and the nonconfidential files 

of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are 

on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree

or type of interest owned been independently confirmed. The technical persons responsible for preparing 

the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, 

and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, 

geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a 

contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

By: /s/ C.H. (Scott) Rees III 

 C.H. (Scott) Rees III, P.E.

 Chairman and Chief Executive Officer

By: /s/ C. Ashley Smith By: /s/ Mike K. Norton 

 C. Ashley Smith, P.E. 100560 Mike K. Norton, P.G. 441

 Vice President Senior Vice President

 Date Signed: April 3, 2013 Date Signed: April 3, 2013

CAS:MSS

Please be advised that the digital document you are viewing is provided by Netherland, Sewell 

& Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be 

substantively the same as the original signed document maintained by NSAI. The digital document is 

subject to the parameters, limitations, and conditions stated in the original document. In the event of any 

differences between the digital document and the original document, the original document shall control and 

supersede the digital document.
F-46

Exhibit 99.2

Source Energy Corp.

3555 Santoro Way, Suite A

San Diego, CA 92130

February 12, 2013

Mr. Stephen Hosmer

Royale Energy, Inc.

7676 Hazard Center Drive, Suite 1500

San Diego, California 92108

Dear Mr. Hosmer:

In accordance with your request, I have estimated the proved reserves and future revenue, as of December 

31, 2012, to the Royale Energy, Inc. (Royale) interest in certain oil and gas properties located in Grand 

County, Utah, as listed in the following tables. I completed my evaluation on or about the date of this letter. 

It is my understanding that the proved reserves estimated in this report constitute approximately 10 percent

of all proved reserves owned by Royale. In my opinion the estimates in this report have been prepared in

accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) and, 

with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards 

Codification Topic 932, Extractive Activities-Oil and Gas. Definitions employed within are taken from 

Netherland, Swell & Associates and are attached.

As presented in the accompanying summary projections I estimate the net reserves and future net revenue to 

the Royale interest in these properties, as of December 31, 2012, to be:

Net 

Reserves Future Net Revenue

Category Gas (MCF) Total

Present Worth 

@10%

Proved Developed

Producing 434,990 $ 841,720 $ 710,160

Proved Developed

Non-Producing 42,790 $ 33,570 $ 28,850

Total Proved 477,780 $ 875,290 $ 739,010

Gas volumes shown above are expressed m thousands of cubic feet (MCF) at standard temperature and 

pressure basis.

The estimates shown in this report are for proved reserves. No study was made to determine whether 

probable or possible reserves might be established for these properties. Reserves categorization conveys the 

relative degree of certainty; reserves subcategorization is based on development and production status. The 

estimates of reserves and future revenue included herein have not been adjusted for risk. As shown in the 

attached tables, for each reserves category this report includes a summary projection of reserves and 

revenue along with one-line summaries of basic data, reserves and economics by well.
F-47

Gross revenue shown in this report is Royale's share of the gross (100 percent) revenue from the properties 

prior to any deductions. Future net revenue is after deductions for Royale's share of production taxes, ad 

valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The 

future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which 

is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, 

whether discounted or undiscounted, should not be construed as being the fair market value of the 

properties.

Gas prices used in this report were provided by Royale and are based on the 12-month unweighted 

arithmetic average of the first-day-of-the-month actual sales price for the period January through December 

2012, or $2.59 per MMBTU. Prices are held constant throughout the lives of the properties.

Lease and well operating costs used in this report are based on operating expense records of Royale. As 

requested, lease and well operating costs for the operated properties are limited to direct lease- and fieldlevel costs and Royale's estimate of the portion of its headquarters general and administrative overhead 

expenses necessary to operate the properties. Lease and well operating costs are held constant throughout the 

lives of the properties. Capital costs are included as required for workovers. The future capital costs are held 

constant to the date of expenditure.

I have performed a field inspection and generally concluded the mechanical operation and condition of the 

wells should not be inconsistent with the attached forecast. I did not observe any environmental liability 

related to the properties and my estimates do not include any costs due to any such liability. Also my 

estimates do not include any salvage value for the leases and well equipment or the cost of abandoning the 

properties. It is my understanding that Royale has fully prefunded accounts that meet or exceed its estimates 

of abandonment costs for the properties, net of any salvage value.

I have made no investigation or inclusion of potential gas volume and value imbalances resulting from overdelivery or under-delivery to the Royale interest. Therefore, my estimates of reserves and future revenue do 

not include adjustments for the settlement of any such imbalances; my projections are based on Royale 

receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved 

reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be 

estimated with reasonable certainty to be economically producible. Estimates of reserves may increase or 

decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir 

performance. In addition to the primary economic assumptions discussed herein, my estimates are based on 

certain assumptions including, but not limited to, that the properties will be developed consistent with 

current development plans, that the properties will be operated in a prudent manner, that no governmental 

regulations or controls will be put in place that would impact the ability of the interest owner to recover the 

estimated amounts, and that my projections of future production will prove consistent with actual 

performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be 

more or less than the estimated amounts because of governmental policies and uncertainties of supply and 

demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may 

vary from assumptions made while preparing this report.

For the purposes of this report, I used technical and economic data including, but not limited to, well logs, 

geologic maps, seismic data, well test data, production data, historical price and cost information, and 

property ownership interests. The reserves in this report have been estimated using deterministic methods; 

these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and 

Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE 

Standards). I used standard engineering and geoscience methods, or a combination of methods, including 

performance analysis, volumetric analysis, and analogy, that I considered to be appropriate and necessary to 
F-48

categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil 

and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; 

therefore, my conclusions necessarily represent only informed professional judgment.

The data used in my estimates were obtained from Royale and were accepted as accurate. Supporting work 

data are on file in my office. The titles to the properties were not been examined by me nor has the actual 

degree or type of interest owned been independently confirmed. I am an independent petroleum engineer 

and do not own an interest in these properties and I am not employed by Royale on a contingent basis.

 

Sincerely,

Source Energy Corp.

James Frimodig

President