UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

ROYALE ENERGY, INC.

(Name of registrant in its charter)

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 o 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 o 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 o

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 o

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. o

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

Large accelerated filer o Accelerated filer o

Non-accelerated filer o Smaller Reporting Company ⌧

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ⌧

At June 30, 2011, the end of the registrant’s most recently completed second fiscal quarter, the aggregate market value of common equity held by non-affiliates was 

$22,156,350.

At December 31, 2011, 10,790,431 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, 

2011, 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.

For the Fiscal Year Ended December 31, 2011 Commission File No. 0-22750

California 33-0224120

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

 

 
Table of Contents 

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 3

ITEM 1B UNRESOLVED STAFF COMMENTS 7 

 ITEM 2 DESCRIPTION OF PROPERTY 7

 Northern California 8

 Developed and Undeveloped Leasehold Acreage 8

 Drilling Activities 8

 Production 9

 Net Proved Oil and Natural Gas Reserves 10

 ITEM 3 LEGAL PROCEEDINGS 10

ITEM 4 MINE SAFETY DISCLOSURES 10 

PART II 11

 ITEM 5 MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 11

 Dividends 11

 Recent Sales of Unregistered Securities 11

 Performance Graph 11

 ITEM 6 SELECTED FINANCIAL DATA 12

 ITEM 7 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 13

 Critical Accounting Policies 13

 Results of Operations for the Twelve Months Ended December 31, 2011, as Compared to the Twelve Months Ended December 

31, 2010

14

 Results of Operations for the Twelve Months Ended December 31, 2010, as Compared to the Twelve Months Ended December 

31, 2009

16

 Capital Resources and Liquidity 17

 Changes in Reserve Estimates 19

 ITEM 7A QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK 19

 ITEM 8 FINANCIAL STATEMENTS 20

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 22

 ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 22

 ITEM 11 EXECUTIVE COMPENSATION 22

 ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 22

 ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 22

 ITEM 14 PRINCIPAL ACCOUNTANT FEES AND SERVICES 22

PART IV 23

 ITEM 15 EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 23

SIGNATURES

FINANCIAL STATEMENTS

24

F-1

 

 
ROYALE ENERGY, INC.

PART I

Item 1 Description of Business

Royale Energy, Inc. ("Royale Energy") is an independent oil and natural gas producer. Royale Energy's principal lines of business are the production and sale of 

natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working 

interests in wells to be drilled by Royale Energy. Royale Energy was incorporated in California in 1986 and began operations in 1988. Royale Energy's common stock 

is traded on the NASDAQ Capital Market System (symbol ROYL). On December 31, 2011, Royale Energy had 23 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 lease that it acquires to third party investors and retains a portion of the prospect for its 

own account. Selling part of the working interest to others allows Royale Energy to reduce its drilling risk by owning a diversified inventory of properties with less of 

its own funds invested in each drilling prospect, than if Royale Energy owned the whole working interest and paid all drilling and development costs of each prospect 

itself. Royale Energy generally sells working interests in its prospects to accredited investors in exempt securities offerings. The prospects are bundled into multiwell 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, 2011, Royale Energy continued to explore and develop natural gas properties with a concentration in California. We also 

acquired over 100,000 acres of prospective oil shale 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 2011, Royale Energy drilled seven wells in northern and central California; four were 

commercially productive wells and three were dry holes. Royale Energy's estimated total reserves decreased from approximately 5.9 BCFE (billion cubic feet 

equivalent) at December 31, 2010 to approximately 4.6 BCFE at December 31, 2011. 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 $10.3 million at December 31, 2011, based on natural gas prices ranging from $3.90 per MCF to $4.35 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, 2011, was estimated to be $5,558,308. 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-28.

Royale Energy reported gross revenues in connection with the drilling of wells on a "turnkey contract" basis, or sales of fractional interests in undeveloped wells, in 

the amount of $5,933,065 for the year ended December 31, 2011, which represents approximately 51% of its total revenues for the year. In 2010, Royale Energy 

reported $7,868,273 gross revenues from turnkey drilling operations for the year, representing 68% of Royale Energy's total revenues for that year.

These amounts are offset by drilling expenses and development costs of $3,523,372 in 2011, and $2,560,068 in 2010. 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 42% of Royale 

Energy's total revenue for the year ended December 31, 2011, came from sales of oil and natural gas from production of its wells in the amount of $4,879,397, in 2010, 

this amount was $3,047,201, which represented 26% of Royale Energy's total revenues.

Table of Contents 

 

1
Plan of Business

Royale Energy acquires interests in oil and natural gas reserves and sponsors private joint ventures. Royale Energy believes that its stockholders are better served 

by diversification of its investments among individual drilling prospects. Through its sale of joint ventures, Royale Energy can acquire interests and develop oil and 

natural gas properties with greater diversification of risk and still receive an interest in the revenues and reserves produced from these properties. By selling some of 

its working interest in most projects, Royale Energy decreases the amount of its investment in the projects and diversifies its oil and gas property holdings, to reduce 

the risk of concentrating a large amount of its capital in a few projects that may not be successful.

After acquiring the leases or lease participation, Royale Energy drills or participates in the drilling of development and exploratory oil and natural gas wells on its 

property. Royale Energy pays its proportionate share of the actual cost of drilling, testing, and completing the project to the extent that it retains all or any portion of 

the working interest.

Royale Energy also may sell fractional interests in undeveloped wells to finance part of the drilling cost. A drilling contract that calls for a company to drill a well, for a 

fixed price, to a specified depth or geological formation is called a "turnkey contract." When Royale Energy sells fractional interests to raise capital to drill oil and 

natural gas wells, generally it agrees to drill these wells on a turnkey contract basis, so that the holders of the fractional interests prepay a fixed amount for the drilling 

and completion of a specified number of wells. Under a turnkey contract, Royale Energy recognizes gross revenue for the amount paid by the purchaser and agrees 

to pay the expense of drilling and development of the well for the participants. Sometimes the actual drilling and development costs are less than the fixed amount 

that Royale Energy received from the fractional interest sale.

When Royale Energy authorizes a turnkey drilling project for sale, a calculation is made to estimate the pre-drilling costs and the drilling costs. A percentage for each 

is calculated. The turnkey drilling project is then sold to investors who execute a contract with Royale Energy. In this agreement, the investor agrees to share in the 

pre-drilling costs, which include lease costs, geological and geophysical costs, and other costs as required so that the drilling of the project can proceed. As stated 

in the contract, the percentage of the pre-drilling costs that the investor contributes is non-refundable, and thus on its financial statements, Royale Energy recognizes 

these non-refundable payments as revenue since the pre-drilling costs have commenced. The remaining investment is held and reported by Royale Energy as 

deferred turnkey drilling until drilling is complete.

Once drilling has commenced, it is generally completed within 10-30 days. See Note 1 to Royale Energy's 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, 2011, Royale Energy earned gross revenues from operation of the wells in the amount of 

$385,575, representing 3.3% of its total revenues for the year. In 2010, the amount was $394,483, which represented about 3.4% of total revenues. At December 31, 

2011, Royale Energy operated 57 natural gas wells in California. Royale also owns an interest and operates seven natural gas wells in Utah and has non-operating 

interests in 12 oil and gas wells in Texas, three in Oklahoma, one in California, and two in Louisiana.

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

some gas is delivered through privately owned pipelines to independent customers. 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 2011.

Table of Contents 

 

2
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 oilproducing regions; and variations in governmental regulations including environmental, energy conservation, and tax laws or the imposition of new regulatory 

requirements upon the oil and natural gas industry.

Regulation

Federal and state laws and regulations affect, to some degree, the production, transportation, and sale of oil and natural gas from Royale Energy’s operations. States 

in which Royale Energy operates have statutory provisions regulating the production and sale of oil and natural gas, including provisions regarding 

deliverability. These statutes, along with the regulations interpreting the statutes, generally are intended to prevent waste of oil and natural gas, and to protect 

correlative rights to produce oil and natural gas by assigning allowable rates of production to each well or proration unit.

The exploration, development, production and processing of oil and natural gas are subject to various federal and state laws and regulations to protect the 

environment. Various federal and state agencies are considering, and some have adopted, other laws and regulations regarding environmental controls that could 

increase the cost of doing business. These laws and regulations may require: the acquisition of a permit by operators before drilling commences; the prohibition of 

drilling activities on certain lands lying within wilderness areas or where pollution arises; and the imposition of substantial liabilities for pollution resulting from 

drilling operations, particularly operations in offshore waters or on submerged lands. The cost of oil and natural gas development and production also may increase 

because of the cost of compliance with such legislation and regulations, together with any penalties resulting from failing to comply with the legislation and 

regulations. Ultimately, Royale Energy may bear 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.

Table of Contents 

 

3
We Depend on Market Conditions and Prices in the Oil and Gas Industry.

Our success depends heavily upon our ability to market oil and gas production at favorable prices. In recent decades, there have been both periods of worldwide 

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

periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis; these periods have been followed by 

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

prices and has resulted in dramatic price fluctuations.

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

continue to produce gas for a profit.

Prices for oil and natural gas affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may 

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

decrease our cash flows, as well as the carrying value of our proved reserves, our borrowing capacity and our ability to obtain additional capital.

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

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

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.

Table of Contents 

• the timing of both production and related expenses;

• changes in consumption levels; and

• governmental regulations or taxation.

 

4
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.

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 contractual 

indemnification rights for pre-closing liabilities, the seller may not fulfill those obligations and leave us with the costs.

Table of Contents 

 

5
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 Hosmer Family Exerts Significant Influence Over Stockholder Matters.

The control positions held by members of the Hosmer family may discourage others from making bids to buy Royale Energy or change its management without their 

consent. Donald H. Hosmer is the co-president of the company. Stephen M. Hosmer is the co-president and chief financial officer. Harry E. Hosmer is the chairman 

of the board. Together, they make up three of the eight members of our board of directors. At March 1, 2012, these individuals owned or controlled the following 

amounts of Royale Energy common stock, including shares they had the right to acquire on the exercise of outstanding stock options:

Table of Contents 

Name 

Number of Shares 

(1) Percent (2), (3) 

Donald H. Hosmer 935,302 8.59%

Stephen M. Hosmer (4) 1,268,235 11.64%

Harry E. Hosmer 683,692 6.28%

Total 2,887,229 26.12%

(1) Includes the following options to purchase shares of stock: Donald H. Hosmer – 50,000, Stephen M. Hosmer – 50,000, and Harry E. Hosmer – 50,000.

(2) Based on total of 10,903,473 outstanding shares on March 1, 2012.

(3) Calculated pursuant to Rule 13d-3 of the Securities and Exchange Commission.

(4) Includes 24,000 shares of stock owned by the minor children of Stephen M. Hosmer. Mr. Hosmer disclaims beneficial ownership of the shares owned by his 

children.

 

6
The amounts of stock owned by Hosmer family members make it quite likely that they could control the outcome of any contested vote of the stockholders on 

matters related to management of the corporation.

The Oil and Gas Industry is Highly Competitive.

The oil and gas industry is highly competitive in all its phases. Competition is particularly intense with respect to the acquisition of desirable producing properties, 

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

development, and production include the major oil companies in addition to numerous independent oil and gas companies, individual proprietors and drilling 

programs.

Many of our competitors possess and employ financial and personnel resources far greater than those which are available to us. They may be able to pay more for 

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

must compete against these larger companies for suitable producing properties and prospects, to generate future oil and gas reserves.

Governmental Regulations Can Hinder Production.

Domestic oil and gas exploration, production and sales are extensively regulated at both the federal and state levels. Legislation affecting the oil and gas industry is 

under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, 

have legal authority to issue, and have issued, rules and regulations affecting the oil and gas industry which often are difficult and costly to comply with and which 

carry substantial penalties for noncompliance. State statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning 

operations. Most states where we operate also have statutes and regulations governing conservation matters, including the unitization or pooling of properties. Our 

operations are also subject to numerous laws and regulations governing plugging and abandonment, discharging materials into the environment or otherwise relating 

to environmental protection. The heavy regulatory burden on the oil and gas industry increases its costs of doing business and consequently affects its 

profitability. Changes in the laws, rules or regulations, or the interpretation thereof, could have a materially adverse effect on our financial condition or results of 

operation.

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

We sometimes acquire less than the controlling working interest in oil and gas properties. In such cases, it is likely that these properties would not be operated by 

us. When we do not have controlling interest, the operator or the other co-owners might take actions we do not agree with and possibly increase costs or reduce 

production income in ways we do not agree with.

Environmental Regulations Can Hinder Production.

Oil and gas activities can result in liability under federal, state and local environmental regulations for activities involving, among other things, water pollution and 

hazardous waste transport, storage, and disposal. Such liability can attach not only to the operator of record of the well, but also to other parties that may be deemed 

to be current or prior operators or owners of the wells or the equipment involved. We have inspections performed on our properties to assure environmental law 

compliance, but inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an 

inspection is undertaken.

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 

2011, Royale Energy drilled seven wells in northern and central California, four of which were commercially productive wells, three are currently producing and one is 

awaiting pipeline hookup. In December 2011, Royale Energy successfully acquired 100,480 acres on the North Slope in a lease sale by the State of Alaska. Out of 13 

companies bidding on 178 tracts, Royale won 60 tracts in the heart of the oil window. The company's 100,480 acre position represents 30% of the 334,969 acres leased 

in this sale. The exact acreage positions will be finalized by the State of Alaska in 2012.

Table of Contents 

 

7
Following industry standards, Royale Energy generally acquires oil and natural gas acreage without warranty of title except as to claims made by, through, or under 

the transferor. In these cases, Royale Energy attempts to conduct due diligence as to title before the acquisition, but it cannot assure that there will be no losses 

resulting from title defects or from defects in the assignment of leasehold rights. Title to property most often carries encumbrances, such as royalties, overriding 

royalties, carried and other similar interests, and contractual obligations, all of which are customary within the oil and natural gas industry.

During 2011, 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, 2011, was $2,750,000. At December 31, 2011, Royale Energy owed $2,750,000 under this 

credit line. Royale uses advances under this credit line to finance lease acquisition operations and for temporary working capital. Following is a discussion of Royale 

Energy's significant oil and natural gas properties. Reserves at December 31, 2011, for each property discussed below, have been determined by Netherland, Sewell & 

Associates, Inc., and Source Energy, LLC, registered professional petroleum engineers, in accordance with reports submitted to Royale Energy on February 22, 2012 

and February 8, 2012, 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, 2011, Royale operated 57 wells in California with estimated total proven, developed, and undeveloped reserves at 

approximately 3.9 BCF, according to Royale’s independently prepared reserve report as of December 31, 2011.

Developed and Undeveloped Leasehold Acreage

As of December 31, 2011, Royale Energy owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.

Table of Contents 

 Developed Undeveloped (1)

 Gross Acres Net Acres Gross Acres Net Acres

California 14,163.02 9,499.80 12,544.03 12,330.92

All Other States 3,691.66 1,678.11 19,322.43 13,988.75

Total 17,854.68 11,177.91 32,866.46 26,319.67

(1) Does not include approximately 100,000 acres being acquired on the North Slope in a December 2011 lease sale by the State of Alaska.

 

8
Drilling Activities

The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2009, 2010 and 2011. All wells are located in the Continental 

U.S., in California, Texas, Louisiana and Utah.

Production

The following table summarizes, for the periods indicated, Royale Energy's net share of oil and natural gas production, average sales price per barrel (BBL), per 

thousand cubic feet (MCF) of natural gas, and the MCF equivalent (MCFE) for the barrels of oil based on a 10 to 1 ratio of the price per barrel of oil to the price per 

MCF of natural gas. "Net" production is production that Royale Energy owns either directly or indirectly through partnership or joint venture interests produced to 

its interest after deducting royalty, limited partner or other similar interests. Royale Energy generally sells its oil and natural gas at prices then prevailing on the "spot 

market" and does not have any material long term contracts for the sale of natural gas at a fixed price.

Table of Contents 

 

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

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

 

2009 Exploratory 3 2 1 0.9715 0.2468

 Developmental 2 1 1 0.4982 0.5369

 

2010 Exploratory 7 5 2 2.0087 0.5686

 Developmental 2 1 1 0.7599 0.5003

 

2011 Exploratory 1 0 1 0.0000 0.4965

 Developmental 6 4 2 2.5184 0.9533

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.

 2011 2010 2009

Net volume

Oil (BBL) 2,264 6,505 8,364

Gas (MCF) 1,144,469 603,206 575,995

MCFE 1,167,109 668,256 659,635

 

Average sales price

Oil (BBL) $ 90.48 $ 70.95 $ 52.92

Gas (MCF) $ 4.08 $ 4.28 $ 4.09

 

Net production costs and taxes $ 1,517,920 $ 1,221,904 $ 1,415,970

 

Lifting costs (per MCFE) $ 1.30 $ 1.83 $ 2.15

 

9
Net Proved Oil and Natural Gas Reserves

As of December 31, 2011, Royale Energy had proved developed reserves of 4,174 MMCF and total proved reserves of 4,570 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 5 MBBL and total proved oil reserves of 5 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 is 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. A proposed judgement 

has been submitted to the Court, and we are awaiting entry of the judgement. It is uncertain if NFC will appeal this 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 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. If 

the case is not dismissed on the jurisdictional motion, Royale intends to answer the complaint and oppose the lawsuit vigorously. 

Item 4 Mine Safety Disclosures

Not Applicable

Table of Contents 

 

10
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, 2011, 10,790,431 

shares of Royale Energy’s Common Stock were held by approximately 4,850 stockholders. The following table reflects the high and low quarterly closing sales prices 

from January 2010 through December 2011.

Dividends

The Board of Directors did not issue cash or stock dividends in 2011 or 2010.

Recent Sales of Unregistered Securities

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. 

In February 2012, four directors exercised stock options to purchase a total of 62,410 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 January 2012, one director exercised stock options, which also had been awarded in 2008, to purchase 

14,654 shares of common stock for cash at an exercise price of $3.50 per share. 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.

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. Exploration and Production Index from December 31, 2006 

through December 31, 2011.

Table of Contents 

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

 High Low High Low High Low High Low 

2011 7.83 2.08 5.52 2.56 3.91 2.08 5.36 1.90 

2010 3.06 2.07 2.50 1.92 2.26 1.83 2.42 1.98 

 

11
Item 6 Selected Financial Data

(In thousands, except earnings per share data)

As of December 31,

Table of Contents 

 2006 2007 2008 2009 2010 2011

Royale Energy, Inc. 100 81 81 77 65 133

S & P Composite 500 

Stock Index 100 104 64 79 89 89

DJ US Exploration and 

Production Index 100 143 85 118 136 130

 2011 2010 2009 2008 2007

Income Statement Data:

 Revenues $ 11,671 $ 11,598 $ 8,626 $ 19,174 $ 16,557

 Operating Income (Loss) (5,644) 1,153 (3,147) (14,362) (3,885)

 Net Income (Loss) (4,104) 1,308 (2,197) (8,778) (2,779)

 Basic Earnings (Loss) Per Share (0.39) 0.12 (0.24) (1.06) (0.35)

Balance Sheet Date:

 Oil & Gas Properties,

 Equipment & Fixtures $ 8,075 $ 10,258 $ 8,800 $ 10,264 $ 23,390

 Total Assets 20,746 23,820 23,564 24,191 32,571

 Long Term Obligations 3,326 3,781 2,954 2,470 6,159

 Total Stockholders’ Equity 7,996 10,938 10,127 7,394 12,385

 

12
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with Royale Energy’s Financial Statements and Notes thereto and other financial information relating to 

Royale Energy included elsewhere in this document.

For the past eighteen years, Royale Energy has primarily acquired and developed producing and non-producing 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 lease that it 

acquires to third party investors and retains a portion of the prospect for its own account. Royale Energy generally retains about a 50% working interest. All results, 

successful or not, are included at its pro rata ownership amounts: revenue, expenses, assets, and liabilities.

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

Royale Energy derives DWI revenue from sales of working interests to high net worth individuals. The DWI revenue is divided into payments for pre-drilling costs 

and for drilling costs. DWI investments are non-refundable. Royale Energy recognizes the pre-drilling revenue portion when the investor deposits money with 

Royale Energy. The company holds the remaining investment as deferred turnkey drilling until drilling is complete. Occasionally, drilling is delayed due to the 

permitting process or drilling rig availability. At December 31, 2011 and 2010, Royale Energy had deferred turnkey drilling of $4,879,853 and $3,866,319 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 2011. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into 

metered transportation and customer pipelines. Monthly, price data and daily production are used to invoice customers for amounts due to Royale Energy and other 

working interest owners. Royale Energy operates virtually all of its own wells and receives industry standard operator fees.

Oil and Gas Property and Equipment

Royale Energy follows the successful efforts method of accounting for oil and gas properties. Costs are accumulated on a field-by-field basis. These costs include 

pre-drilling activities such as leasing rents paid, drilling costs, and post-drilling tangible costs. Costs of unproved properties are excluded from amortization until the 

properties are evaluated. Royale Energy regularly evaluates its unproved properties on a field-by-field basis for possible impairment. Due to the unpredictable nature 

of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty.

Depletion

The units of production method of accounting uses proved reserves in the calculation of depletion, depreciation and amortization. Proved reserves are estimated 

quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from 

known reservoirs under existing economic and operating conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgment 

determinations. Independent engineering reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir 

performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and Royale 

Energy considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The independent 

engineering estimates include only those amounts considered to be proved 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.

Table of Contents 

 

13
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 non-producing 

leasehold costs and undeveloped mineral and royalty interests are assessed periodically on a property-by-property basis and any impairment in value is charged to 

expense. We periodically review for impairment of proved properties on a field-by-field basis. Unamortized capital costs are measured on a field basis and are 

reduced to fair value if it is determined that the sum of expected future net cash flows are less than the net book value. We determine if impairment has occurred 

through either adverse changes or as a result of its periodic review for impairment. Impairment is measured on 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.

Deferred Income Taxes

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been 

recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for 

deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Results of Operations for the Twelve Months Ended December 31, 2011, as Compared to the Twelve Months Ended December 31, 2010

For the year ended December 31, 2011, we recorded a net loss of $4,104,338 a $5,412,366 decline when compared to our net profit of $1,308,028 during 2010. This 

reduction was primarily due to an impairment of our oil and gas properties of $4,529,058 and lower turnkey drilling revenues due to a decrease in the number of wells 

drilled during 2011. Total revenues from operations for the year in 2011 were $11,671,048, an increase of $72,608, or 1%, from the total revenues of $11,598,440 in 2010, 

the result of higher sales of oil and natural gas.

In 2011, revenues from oil and gas production increased by 60.1% to $4,879,397 from $3,047,201 in 2010, due to higher natural gas production as three wells, two of 

which were drilled during the fourth quarter of 2010, were brought online early in 2011. The net sales volume of natural gas for the year ended December 31, 2011, was 

approximately 1,144,469 MCF with an average price of $4.08 per MCF, versus 603,330 MCF with an average price of $4.28 per MCF for 2010. This represents an 

increase in net sales volume of 541,139 MCF or 89.7%. The net sales volume for oil and condensate (natural gas liquids) production was approximately 2,264 barrels 

with an average price of $90.48 per barrel for the year ended December 31, 2011, compared to 6,511 barrels at an average price of $70.95 per barrel for the year in 

2010. This represents a decrease in net sales volume of 4,247 barrels, or 65.2%. 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 increased by $296,016, or 24.2%, to $1,517,920 for the year ended December 31, 2011, from $1,221,904 for the year in 2010. This 

increase was mainly due to higher transportation costs stemming from the increased production in 2011. When measuring lease operating costs on a production or 

lifting cost basis, in 2011, the $1,517,920 equates to a $1.30 per MCFE lifting cost versus a $1.83 per MCFE lifting cost in 2010, a 29% decrease.

Table of Contents 

 

14
For the year ended December 31, 2011, turnkey drilling revenues decreased $1,935,208 to $5,933,065 from $7,868,273 in 2010, or 24.6%. We also had a $963,304 or 

37.6% increase in turnkey drilling and development costs to $3,523,372 in 2011 from $2,560,068 in 2010. In 2011 we drilled seven wells, six developmental wells and 

one exploratory well versus nine wells, seven exploratory wells and two developmental wells in 2010, which lead to our decrease in turnkey revenues. Turnkey costs 

increased because the wells drilled in 2011 were deeper and more expensive than those drilled in 2010. 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 decreased to 40.6% from 67.5% for the years ended December 31, 2011 and 2010, 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 $4,529,058 and $500,144 were recorded in 2011 and 2010, respectively. In both years, we recorded impairments in 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 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. In 2010, the River Island, Dunnigan Hills, Rio Vista and Bowerbank 

fields were impaired $233,521, $22,118 and $17,931, $24,680 respectively for the same reason. Additionally in 2011 and 2010, we recorded lease impairments of $12,959 

and $201,883 respectively, on various capitalized lease and land costs that were no longer viable.

Bad debt expense for 2011 and 2010 were $86,294 and $43,153, 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 $858,586 for the year ended December 31, 2011, an increase of $175,620 (25.7%) from $682,966 during the 

year in 2010. This increase was mainly due to higher pipeline and compressor revenues generated from the increase 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 decreased $8,908 or 2.3%, to $385,575 in 2011 from $394,483 

in 2010.

Depreciation, depletion and amortization expense increased to $2,362,065 from $919,355 an increase of $1,442,710 (156.9%) for the year ended December 31, 2011, as 

compared to 2010. The depletion rate is calculated using production as a percentage of reserves. This increase in depletion expense was mainly due to the higher 

natural gas production during 2011 resulting in an increased depletion rate of our oil and natural gas properties.

General and administrative expenses increased slightly by $37,839 or 1%, from $4,001,370 for the year ended December 31, 2010, to $4,039,209 for the year in 

2011. This increase was primarily due to higher employee related costs. Legal and accounting expense increased to $933,856 for the year, compared to $574,384 for 

2010, a $359,472 or 62.6% increase. This increase was the result of higher legal fees in 2011 primarily related to the conclusion of the Mountain West and National 

Fuel litigation.

Marketing expense for the year ended December 31, 2011, increased $91,964 or 14.8%, to $713,495, compared to $621,531 for the year in 2010. Marketing expense 

usually varies from period to period according to the number of marketing events attended by personnel and their associated costs.

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. Additionally during 2011, we had a write down of $258,043 on certain oil and gas pipeline inventory to its estimated 

current market value. In 2010, we recorded a loss of $3,310 on the sales of non-oil and gas assets.

During 2010, we received title to securities stemming from a litigation settlement received approximately 10 years ago; the securities at that time had an 

undeterminable value. In June 2010, Royale began to liquidate its position and during the third quarter had fully liquidated its position. In 2010, the 

Company recognized a net unrealized holding loss of $676,563 in the other comprehensive income section of the Statement of Operations, and a realized gain of 

$907,679 from the complete liquidation of these securities in the other income section of the Statement of Operations. 

Table of Contents 

 

15
During 2011, interest expense increased to $138,218 from $46,613 in 2010, a $91,605 or 196.5% increase. This was due to an increase in the usage of our bank line of 

credit. Further details concerning Royale’s line of credit usage can be found in the Capital Resources and Liquidity section below.

In 2011, we had income tax benefit of $1,677,771 due to our net loss before taxes of $5,782,109. In 2010, we had an income tax expense of $706,259 due to our net profit 

before taxes of $2,014,287. For 2011, 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%).

Results of Operations for the Twelve Months Ended December 31, 2010, as Compared to the Twelve Months Ended December 31, 2009

For the year ended December 31, 2010, we achieved a net profit of $1,308,028, a $3,505,171 improvement when compared to our net loss of $2,197,143 during 

2009. This improvement was primarily due to higher turnkey drilling revenues due to an increase in the number of wells drilled during 2010. Total revenues from 

operations for the year in 2010 were $11,598,440, an increase of $2,972,855, or 34.5%, from the total revenues of $8,625,585 in 2009, also the result of higher turnkey 

drilling revenues.

In 2010, revenues from oil and gas production increased by 8.8% to $3,047,201 from $2,800,557 in 2009, due to slight increases in both production and the commodity 

prices received for our oil and natural gas production. The net sales volume of natural gas for the year ended December 31, 2010, was approximately 603,330 MCF 

with an average price of $4.28 per MCF, versus 575,995 MCF with an average price of $4.09 per MCF for 2009. This represents an increase in net sales volume of 

27,335 MCF or 4.7%. This increase was due to higher production volumes of wells drilled and put online during the latter part of the year. The net sales volume for 

oil and condensate (natural gas liquids) production was approximately 6,511 barrels with an average price of $70.95 per barrel for the year ended December 31, 2010, 

compared to 8,364 barrels at an average price of $52.92 per barrel for the year in 2009. This represents a decrease in net sales volume of 1,853 barrels, or 22.2%.

Oil and gas lease operating expenses decreased by $194,066, or 13.7%, to $1,221,904 for the year ended December 31, 2010, from $1,415,970 for the year in 2009. This 

decrease was mainly due to continuing cost control measures, lower workover costs and other reduced lease operating costs during 2010. When measuring lease 

operating costs on a production or lifting cost basis, in 2010, the $1,221,904 equates to a $1.83 per MCFE lifting cost versus a $2.15 per MCFE lifting cost in 2009, a 

14.9% decrease.

For the year ended December 31, 2010, turnkey drilling revenues increased $2,806,469 to $7,868,273 from $5,061,804 in 2009, or 55.4%. We also had a $413,164 or 19.2% 

increase in turnkey drilling and development costs to $2,560,068 in 2010 from $2,146,904 in 2009. In 2010 we drilled nine wells, seven exploratory wells and two 

developmental wells versus five wells, three exploratory wells and two developmental wells in 2009. 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 67.5% from 57.6% for the years ended December 31, 2010 and 2009, 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 $500,144 and $1,935,861 were recorded in 2010 and 2009, respectively. In both years, we recorded impairments in fields where year end reserve 

values were less than the net book values of wells or where lease and land costs that were no longer viable. In 2010, the River Island field was impaired $233,521 due 

to lower proved producing reserves than current book values. Additionally, two other California fields, Dunnigan Hills, and Rio Vista were impaired $22,118 and 

$17,931, respectively, also due to lower proved producing reserves than current book values. Our Bowerbank field in California was impaired $24,680 due to lower 

proved undeveloped reserves than current book values. In 2009, the majority of the impairment, $1,124,293, was recorded in our Utah fields, where various recently 

drilled wells had significantly lower proved developed nonproducing reserves than originally estimated. Much of these were costs carried over from wells drilled in 

2008. Our Elkhorn Slough and East Rice Creek fields, both in California, were impaired $341,098 and $205,173, respectively, due to lower proved producing reserves 

than their current book values. Two other California fields, the Rio Vista and Bowerbank, were impaired $74,124 and $71,975, respectively, due to lower proved 

undeveloped reserves than originally estimated. Additionally in 2010 and 2009, we recorded lease impairments of $201,883 and $112,165, respectively, on various 

capitalized lease and land costs that were no longer viable.

Table of Contents 

 

16
Bad debt expense for 2010 and 2009 were $43,153 and $255,478, 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. In 2010 and 2009, approximately 79% and 78%, respectively, of 

these expenses arose from two of our California wells. 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. As a result of those reviews in 2009 we increased 

the allowance $49,699 for receivables from these Direct Working Interest owners. There were no such increases in 2010.

The aggregate of supervisory fees and other income was $682,966 for the year ended December 31, 2010, a decrease of $80,258 (10.5%) from $763,224 during the year 

in 2009. This decrease was mainly due to the 2009 granting of a seismic license to an industry member for which we were compensated. Supervisory fees are charged 

in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for reimbursement of expenses associated with the joint accounting for billing, 

revenue disbursement, and payment of taxes and royalties. These charges are reevaluated each year and adjusted up or down as deemed appropriate by a published 

report to the industry by Ernst & Young, LLP, Public Accountants. Supervisory fees increased $5,747 or 1.5%, to $394,483 in 2010 from $388,736 in 2009.

Depreciation, depletion and amortization expense decreased to $919,355 from $989,716 a decrease of $70,361 (7.1%) for the year ended December 31, 2010, as 

compared to 2009. The depletion rate is calculated using production as a percentage of reserves. This decrease in depletion expense was mainly due to the decrease 

in our oil and gas asset base from our 2009 impairments.

General and administrative expenses increased by $454,554 or 12.8%, from $3,546,816 for the year ended December 31, 2009, to $4,001,370 for the year in 2010. This 

increase was primarily due to higher employee related expenses such as salaries, taxes and insurances. Legal and accounting expense decreased to $574,384 for the 

year, compared to $717,173 for 2009, a $142,789 or 19.9% decrease. This decrease stems from higher legal fees incurred during the first two quarters of 2009 pertaining 

to the Pioneer litigation.

Marketing expense for the year ended December 31, 2010, decreased $188,616 or 23.3%, to $621,531, compared to $810,147 for the year in 2009. Marketing expense 

usually varies from period to period according to the number of marketing events attended by personnel and their associated costs. In 2010, our cost containment 

measures led to decreases primarily in exhibition costs.

In 2010, we recorded a loss of $3,310 on the sales of non-oil and gas assets. In 2009, we recorded a gain on the sales of assets of $45,611 that can be primarily 

attributable to a reconciling adjustment gain of $170,713 from our 2008 Rio Bravo sale and a loss from the sale of marketable securities of $120,219.

During the second quarter of 2010, we received title to securities stemming from a litigation settlement received approximately 10 years ago; the securities at that time 

had an undeterminable value. In June 2010, Royale began to liquidate its position and during the third quarter had fully liquidated its position. For 2010, the 

Company has recognized a net unrealized holding loss of $676,563 in the other comprehensive income section of the Statement of Operations, and a realized gain of 

$907,679 from the complete liquidation of these securities in the other income section of the Statement of Operations.

During 2010, interest expense decreased to $46,613 from $101,675 in 2009, a $55,062 or 54.2% decrease. This was due to a decrease in the usage of our bank line of 

credit. Further details concerning Royale’s line of credit usage can be found in the Capital Resources and Liquidity section below.

In 2010, we had income tax expense of $706,259 due to our net profit before taxes of $2,014,287. In 2009, we had an income tax benefit of $1,051,401 due to our net loss 

before taxes of $3,248,544. For 2009, the use of percentage depletion created from the current operations, and from utilization of unused percentage depletion 

carryforwards, results in an effective tax rate less than the normal federal rate of 34% plus the relevant state rates (mostly California, 9.3%).

Capital Resources and Liquidity

At December 31, 2011, Royale Energy had current assets totaling $6,607,496 and current liabilities totaling $9,423,834, a $2,816,338 working capital deficit. We had 

cash and cash equivalents at December 31, 2011 of $2,946,131 compared to $4,630,722 at December 31, 2010.

Table of Contents 

 

17
Our capital expenditure commitments occur as we decide to drill wells to develop our prospects. We generally do not decide to drill any prospect until we have sold a 

portion of the working interest in a prospect to third parties to diversify our risk and receive a portion of the funds to drill each prospect. We place funds that we 

receive from third party investors into a separate cash account until they are required for expenditures on each well. Our capital expenditure needs in addition to 

those needs are satisfied by selling part of the working interest in prospects.

We expect that our available credit and cash flows from operations will be sufficient for capital expenditure needs beyond those satisfied from sales of working 

interests. We ordinarily fund our operations and cash needs from cash flows generated from operations. We believe that we have sufficient liquidity for 2012 and do 

not foresee any liquidity demands that cannot be met from cash flow from operations.

At the end of 2011, our accounts receivable totaled $1,872,067 compared to $2,451,047 at December 31, 2010, a $578,980 or 23.6% decrease. This was primarily due to 

lower oil and gas receivables due to a decline in natural gas production at the end of the year when compared to the year end December 31, 2010. At December 31, 

2011, our accounts payable and accrued expenses totaled $4,542,741, a decrease of $692,425 or 13.2% over the accounts payable at the end of 2010 of $5,235,166. This 

decrease was mainly due to decreased drilling activity at year end 2011 when compared to year end 2010.

In February 2009, we entered into a new 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. Under the terms of the agreement, Royale Energy may borrow, repay, 

and re-borrow funds as necessary. Interest is to be the greater of Texas Capital Bank’s base rate margin plus 1% and the Federal Funds rate but in no event less than 

5% per year. On June 1, 2011, Texas Capital Bank re-determined the borrowing base to be $3,250,000 with monthly borrowing base reductions of $100,000 

commencing on July 1, 2011. All unpaid principal and interest is payable at maturity on February 13, 2013. At December 31, 2011, we had a current borrowing base 

and outstanding indebtedness on this loan of $2,750,000.

The Texas Capital Bank loan agreement contains certain restrictive covenants, including a prohibition of payment of dividends on Royale’s stock (other than 

dividends paid in stock). The loan agreement contains covenants that, among other things, Royale must:

At December 31, 2011, we were not in compliance with the current ratio financial covenant of our loan agreement with the bank, but we have obtained a waiver from 

the terms of that loan covenant. We are not in default on any principal, interest or sinking fund payment.

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, 2011, and the effect such obligations are expected to have on our 

liquidity and cash flow in future periods.

Table of Contents 

• Maintain a minimum ratio of earnings before interest, taxes, depreciation and amortization to interest expense of at least 3.00 to 1.00;

• Maintain a ratio of current assets to current liabilities, as defined in the agreement, of at least 1.00 to 1.00; and

• Maintain a tangible net worth as of the close of each fiscal quarter of at least 75% of Royale’s tangible net worth on the loan closing date, plus 75% of 

positive quarterly net income thereafter.

 Total Obligations 2012 2013-2014 2015-2016 Beyond

 

Office lease $ 1,458,307 $ 391,692 $ 819,715 $ 246,900 $ -

Long-term debt 2,750,000 - 2,750,000 -

Total $ 4,208,307 $ 391,692 $ 3,569,715 $ 246,900 $ -

 

18
Operating Activities. For the year ended December 31, 2011, cash provided by operating activities totaled $1,662,385 compared to $2,063,517 provided by operating 

activities for the year in 2010, a decrease of $401,132 or 19.4%. This decrease in cash provided was due to higher direct working interest sales and the paying down 

on our accounts payable during the year in 2011. For the year ended December 31, 2010, cash provided by operating activities totaled $2,063,517 compared to 

$884,369 used by operating activities for the year in 2009. This difference in cash was due to our increased drilling activity in 2010 and lower direct working interest 

sales during the year in 2009.

Investing Activities. For the year ended December 31, 2011, cash used by investing activities was $3,948,464 compared to $1,973,077 used by investing activities in 

2010, an increase of $1,975.387 or 100.1%. This increase was the result of drilling fewer but deeper and more expensive wells during 2011. During 2011 we also 

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. During the year in 2010 we received $907,679 from the sale of settlement stock mentioned previously. For the 

year ended December 31, 2010 cash used by investing activities of $1,973,077 compared to $965,928 used by investing activities in 2009, an increase of $1,007,149 or 

104.3%. This increase was due to our increased drilling activity in 2010 when compared to 2009.

Financing Activities. For the year ended December 31, 2011, cash provided by financing activities was $601,488 compared to $705,000 provided by financing 

activities in 2010, a $103,512 or 14.7% decrease. During the year 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. In 2010, the $705,000 was loan proceeds from our letter of credit facility with Texas 

Capital Bank. For the year ended December 31, 2009, cash provided by financing activities was $4,354,840. In August 2009, Royale Energy received net proceeds of 

$985,314 through the sale of common stock and warrants to one investor in a private placement. The proceeds were used to increase our stockholders’ equity and 

working capital. Additionally, during September and October 2009 we received net proceeds of $1,080,650 from the exercise of warrants for 511,628 shares from the 

August 2009 private placement. In October 2009, Royale Energy received net proceeds of $1,824,850 through the private placement of common stock and warrants to 

one investor. The proceeds were used to assist in the development a new natural gas field discovery in California. During the first quarter of 2009, we paid off our 

line of credit with Guaranty Bank and established a new one with Texas Capital Bank.

Changes in Reserve Estimates

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. See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-28.

During 2010, while our overall proved developed and undeveloped reserves increased by 24.2% our previously estimated proved developed and undeveloped 

reserve quantities were revised downward by approximately 0.5 million cubic feet of natural gas. This downward revision was primarily due one California well drilled 

in 2009 which had lower than previously estimated proved producing gas reserves.

In 2009, our overall proved developed and undeveloped reserves increased by 36.8% in 2009 while our previously estimated proved developed and undeveloped 

reserve quantities were revised downward slightly by approximately .4 million cubic feet of natural gas. Approximately 75% of the revision came from three existing 

California wells

which had lower than previously estimated proved producing gas reserves. The other 25% came from two California prospects which had been previously estimated 

to contain proved undeveloped gas reserves, were reevaluated and found to have lower than expected reserves and as a result were not drilled.

Item 7A Qualitative and Quantitative Disclosures About Market Risk

Royale Energy is exposed to market risk from changes in commodity prices and in interest rates. In 2011, we sold a majority of our natural gas at the daily market rate 

through the Pacific Gas & Electric pipeline. In 2011, our natural gas revenues were approximately $4.7 million with an average price of $4.08 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 $466,943. 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 $20,482. We currently do not sell any of our natural gas or oil through hedging 

contracts.

Table of Contents 

 

19
We have a line of credit used in funding purchases of oil and gas assets, meeting drilling schedules and assisting in funding operations. This line of credit is tied to 

increases or decreases in the bank prime interest rate. If the interest rate on our line of credit were to increase 1% or 2% during the year this could potentially add 

approximately $27,500 to $55,000, respectively, to our interest expense.

Item 8 Financial Statements and Supplementary Data

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

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, evaluated the effectiveness or our disclosure controls and procedures as of the end of 

the 2011 fiscal year. Based on their evaluation, they concluded that our disclosure controls are effective as of December 31, 2011.

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, 2011, 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.

Table of Contents 

 

20
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.

Changes in Internal Control over Financial Reporting

No changes in our internal control over financial reporting occurred during the last fiscal quarter of 2011 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.

Table of Contents 

 

21
PART III

Item 10 Directors and Executive Officers of the Registrant

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will 

be filed with the SEC and mailed to stockholders within 120 days of December 31, 2011.

Item 11 Executive Compensation

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will 

be filed with the SEC and mailed to stockholders within 120 days of December 31, 2011.

Item 12 Security Ownership of Certain Beneficial Owners and Management

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will 

be filed with the SEC and mailed to stockholders within 120 days of December 31, 2011.

Item 13 Certain Relationships and Related Transactions

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will 

be filed with the SEC and mailed to stockholders within 120 days of December 31, 2011.

Item 14 Principal Accountant Fees and Services

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will 

be filed with the SEC and mailed to stockholders within 120 days of December 31, 2011.

Table of Contents 

 

22
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:

* 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.

Table of Contents 

• 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-29.

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

3.1 Restated Articles of Incorporation of Royale Energy, Inc., incorporated by reference to Exhibit 3.1 of Royale Energy’s Form 10-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 Warrant issued to Cranshire Capital, L.P., incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K filed August 6, 2009.

4.2 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.

4.3 Series B Warrant issued to Cranshire Capital, L.P., incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K filed August 6, 2009.

4.4 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.

4.5 Warrant issued to J.P. Turner Partners, L.P. dated August 5, 2009, incorporated by reference to Exhibit 4.5 of the Company’s Form S-3/A filed August 

21, 2009.

4.6 Warrant issued to J.P. Turner Partners, L.P. dated October 20, 2009, incorporated by reference to Exhibit 4.6 of the Company’s Form S-3/A filed 

December 14, 2009.

4.7 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.

4.8 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 Financial Representative Agreement between the Company and J.P. Turner & Company, LLC, dated July 9, 2009, incorporated by reference to Exhibit 

10.3 of the Company’s Form S-3/A filed August 21, 2009.

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.

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

 

23
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.

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.

Table of Contents 

 Royale Energy, Inc.

 

Date: March 14, 2012 /s/ Donald H.. Hosmer

 Donald H.. Hosmer

 Co-President and Co-Chief Executive Officer

 

Date: March 14, 2012 /s/ Harry E. Hosmer

Harry E. Hosmer

Chairman of the Board of Directors

Date: March 14, 2012 /s/ Donald H. Hosmer

Donald H. Hosmer

Director, Co-President, Co-Chief Executive Officer

Date: March 14, 2012 /s/ Stephen M. Hosmer

Stephen M. Hosmer

Director, Co-President, Co-Chief Executive Officer, Chief Financial Officer and Secretary

Date: March 14, 2012 /s/ Tony Hall

Tony Hall

Director

Date: March 14, 2012 /s/ Oscar A. Hildebrandt

Oscar A. Hildebrandt

Director

Date: March 9, 2012 /s/ Gary Grinsfelder

Gary Grinsfelder

Director

Date: March 14, 2012 /s/ George M. Watters

George M. Watters

Director

 

24
ROYALE ENERGY, INC. 

INDEX TO FINANCIAL STATEMENTS 

AND SUPPLEMENTARY DATA

TABLE OF CONTENTS

Table of Contents 

REPORT OF PADGETT, STRATEMANN & CO., LLP, INDEPENDENT AUDITORS F-2

BALANCE SHEETS DECEMBER 31, 2011 AND 2010 F-3

STATEMENTS OF OPERATIONS F-5

STATEMENTS OF STOCKHOLDERS’ EQUITY F-6

STATEMENTS OF CASH FLOWS F-7

NOTES TO FINANCIAL STATEMENTS F-8

 

F-1
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, 2011 and 2010, and the related statements of 

operations, stockholders' equity, and cash flows for the years ended December 31, 2011, 2010 and 2009. 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, 2011 

and 2010, and the results of its operations and its cash flows for the years ended December 31, 2011, 2010 and 2009 in conformity with accounting principles generally 

accepted in the United States of America.

Padgett, Stratemann & Co., L.L.P.

San Antonio, Texas

March 14, 2012

Table of Contents 

 

F-2
ROYALE ENERGY, INC

BALANCE SHEETS

DECEMBER 31, 2011 AND 2010

ASSETS

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

Table of Contents 

 2011 2010

 

Current Assets

Cash and Cash Equivalents $ 2,946,131 $ 4,630,722

Accounts Receivable, net 1,872,067 2,451,047

Prepaid Expenses 432,168 586,486

Deferred Tax Asset 661,645 541,442

Available for Sale Securities 31,027 0

Inventory 664,458 850,385

Total Current Assets 6,607,496 9,060,082

Other Assets 6,946 6,946

Deferred Tax Asset - Noncurrent 6,055,803 4,495,145

 

Oil And Gas Properties (Successful Efforts Basis)

Equipment and Fixtures 8,075,344 10,258,240

Total Assets $ 20,745,589 $ 23,820,413

 

F-3
ROYALE ENERGY, INC.

BALANCE SHEETS

DECEMBER 31, 2011 AND 2010

LIABILITIES AND STOCKHOLDERS' EQUITY

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

Table of Contents 

 2011 2010

Current Liabilities:

Accounts Payable and Accrued Expenses $ 4,542,741 $ 5,235,166

Current Portion of Deferred Tax Liability 1,240 0

Deferred Revenue from Turnkey Drilling 4,879,853 3,866,319

Total Current Liabilities 9,423,834 9,101,485

 

Noncurrent Liabilities:

Asset Retirement Obligation 575,612 580,568

Long-Term Debt 2,750,000 3,200,000

 

Total Noncurrent Liabilities 3,325,612 3,780,568

 

Total Liabilities 12,749,446 12,882,053

Stockholders' Equity

 

Common Stock, No Par Value, 20,000,000 Shares Authorized; 10,823,050 and 10,307,350 Shares Issued, 10,790,431 and 

10,274,731 Shares Outstanding, Respectively 28,298,228 27,246,740

 

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) (20,911,762) (16,807,424)

Accumulated Other Comprehensive Income (Loss) 3,035 0

 

Total Paid in Capital and Accumulated Deficit 7,543,515 10,593,330

Less Cost of Treasury Stock, 32,619 Shares (179,376) (179,376)

Paid in Capital, Treasury Stock 632,004 524,406

 

Total Stockholders' Equity 7,996,143 10,938,360

 

 

Total Liabilities and Stockholders' Equity $ 20,745,589 $ 23,820,413

 

F-4
ROYALE ENERGY, INC.

STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009

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

Table of Contents 

 2011 2010 2009

Revenues:

Sale of Oil and Gas $ 4,879,397 $ 3,047,201 $ 2,800,557

Turnkey Drilling 5,933,065 7,868,273 5,061,804

Supervisory Fees and Other 858,586 682,966 763,224

Total Revenues $ 11,671,048 $ 11,598,440 $ 8,625,585

Costs and Expenses:

General and Administrative 4,039,209 4,001,370 3,546,816

Turnkey Drilling & Development 3,523,372 2,560,068 2,146,904

Lease Operating 1,517,920 1,221,904 1,415,970

Lease Impairment 4,529,058 500,144 1,935,861

Geological and Geophysical 111,390 0 0

Inventory Write Down 258,043 0 0

Bad Debt Expense 86,294 43,153 255,478

Legal and Accounting 933,856 574,384 717,173

Marketing 713,495 621,531 810,147

Depreciation, Depletion and Amortization 2,362,065 919,355 989,716

Total Costs and Expenses $ 18,074,702 $ 10,441,909 $ 11,818,065

Gain (Loss) on Sale of Assets 759,763 (3,310) 45,611

 

Income (Loss) from Operations (5,643,891) 1,153,221 (3,146,869)

Other Income (Expense):

Interest Expense (138,218) (46,613) (101,675)

Gain on sale of Marketable Securities 0 907,679 0

Income (Loss) Before Income Tax Expense (5,782,109) 2,014,287 (3,248,544)

Income Tax Expense (Benefit) (1,677,771) 706,259 (1,051,401)

Net Income (Loss) $ (4,104,338) $ 1,308,028 $ (2,197,143)

Basic Earnings Per Share:

Net Income (Loss) Available To Common Stock $ (0.39) $ 0.13 $ (0.24)

Diluted Earnings (Loss) Per Share $ (0.39) $ 0.12 $ (0.24)

 

Other Comprehensive Income

 Unrealized Gain(Loss) on Equity Securities $ 4,275 $ (1,907,999) $ 1,352,465

 Less: Reclassification Adjustment for Losses (Gains) Included in Net Income 0 (907,679) 120,269

 

Other Comprehensive Income (Loss), before tax 4,275 (1,000,320) 1,232,196

 

Income Tax Expense (Benefit) Related to Items of Other Comprehensive Income 1,240 (323,757) 415,580

 

Other Comprehensive Income (Loss), net of tax 3,035 (676,563) 816,616

 

Comprehensive Income (Loss) $ (4,101,303) $ 631,465 $ (1,380,527)

 

F-5
ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009

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

Table of Contents 

Common Stock 

Preferred Stock 

Series AA Treasury Stock

 

Shares 

Issued Amount 

Shares 

Outstanding 

 

Amount 

Shares

Acquired Amount 

Paid in

Capital

Treasury

Stock 

Accumulated

Deficit 

Accumulated

Other

Comprehensive

Income

(Loss) Total 

 

Balance at January 1, 2009 8,538,717 $23,355,926 52,784 $154,014 32,619 $ (179,376) $ 122,265 $ (15,918,309) $ (140,053) $ 7,394,467 

 

Common Stock Private 

Placement 1,175,817 2,810,164 - - - - 74,748 - - 2,810,164 

 

Common Stock Warrant 

Exercise 511,628 1,080,650 - - - - - - - 1,080,650 

 

Conversion of Preferred AA - - - - - - 147,834 - - - 

 

Directors’ Stock Option Grant 31,665 - - - - - - - - 74,748 

 

Stock Options Exercised - - - - - - - - - - 

 

Employee Stock Award 

Adjustment - - - - - - - - - - 

 

Directors’ Stock Grant - - - - - - - - - 174,834 

 

Available for Sale Securities –

Unrealized Gain (Loss), net of 

tax - - - - - - - - 816,616 816,616 

 

Net Loss (2,197,143) (2,197,143) 

 

Balance, December 31, 2009 10,257,827 $27,246,740 52,784 $154,014 32,619 $ (179,376) $ 344,847 $ (18,115,452) $ 676,563 $ 10,127,336 

 

Common Stock Private 

Placement - - - - - - - - - - 

 

Common Stock Warrant 

Exercise - - - - - - - - - - 

 

Directors’ Stock Option Grant 49,523 - - - - - 74,748 - - 74,748 

 

Directors’ Stock Grant - - - - - - 104,811 - - 104,811 

 

Available for Sale Securities –

Unrealized Gain (Loss), net of 

tax - - - - - - - - (676,563) (676,563) 

 

Net Income (Loss) 1,308,028 1,308,028 

 

Balance, December 31, 2010 10,307,350 $27,246,740 52,784 $154,014 32,619 $ (179,376) $ 524,406 $ (16,807,424) $ - $ 10,938,360 

 

Common Stock Warrant 

Exercise 468,928 $ 1,051,488 - - - - - - - 1,051,487 

 

Directors’ Stock Options Grant 18,440 - - - - - 40,015 - - 40,015 

 

Directors’ Stock Grant 28,332 - - - - - 67,583 - - 67,583 

 

Available for Sale Securities –

Unrealized Gain (Loss), net of 

tax - - - - - - - - 3,035 3,035 

 

Net Income (Loss) - - - - (4,104,338) (4,104,339) 

 

Balance, December 31, 2011 10,823,050 $28,298,228 52,784 $154,014 32,619 $ (179,376) $ 632,004 $ (20,911,762) $ 3,035 $ 7,996,143 

 

F-6

ROYALE ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

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

Table of Contents 

 2011 2010 2009 

 

CASH FLOWS FROM OPERATING ACTIVITIES: 

Net Income (Loss) $ (4,104,338) $ 1,308,028 $ (2,197,143)

Adjustments to Reconcile Net Income (Loss) to Net Cash (Used in) Provided by Operating 

Activities: 

Depreciation, Depletion, and Amortization 2,362,065 919,355 989,716 

Lease Impairment 4,529,058 500,144 1,935,861 

(Gain) Loss on Sale of Assets (759,763) 3,310 (165,880)

Realized (Gain) Loss on Equity Securities 0 (907,679) 120,269 

Bad Debt Expense 86,294 43,153 255,478 

Stock-Based Compensation, net of adjustments 107,598 179,559 222,582 

Inventory Write Down 258,043 0 0 

(Increase) Decrease in: 

Accounts Receivable 492,686 (1,092) 1,001,971 

Prepaid Expenses and Other Assets 82,202 251,229 1,368,094 

Increase (Decrease) in: 

Accounts Payable and Accrued Expenses (724,133) 176,969 (5,120,590)

Deferred Revenues - DWI 1,013,534 (1,113,286) 973,805 

Deferred Income Taxes (1,680,861) 703,827 (268,532)

 

Net Cash (Used in) Provided by Operating Activities 1,662,385 2,063,517 (884,369)

 

CASH FLOWS FROM INVESTING ACTIVITIES: 

Expenditures For Oil And Gas Properties and 

 Other Capital Expenditures (4,754,817) (2,895,475) (1,430,955)

Proceeds from Sale of Assets 806,353 14,719 134,482 

Purchase of Equity Securities 0 (177,624) (8,857)

Sale of Equity Securities 0 1,085,303 339,402 

 

Net Cash Used in Investing Activities (3,948,464) (1,973,077) (965,928)

 

CASH FLOWS FROM FINANCING ACTIVITIES: 

Proceeds from Long-Term Debt 700,000 9,020,000 7,443,764 

Principal Payments on Long-Term Debt (1,150,000) (8,315,000) (6,979,738)

Proceeds from Issuance of Common Stock 0 0 2,810,164 

Exercise of Options and Warrants for Cash 1,051,488 0 1,080,650 

 

Net Cash Provided by Financing Activities 601,488 705,000 4,354,840 

 

Net Increase (Decrease) in Cash and Cash Equivalents (1,684,591) 795,440 2,504,543 

 

Cash & Cash Equivalents at Beginning of Year 4,630,722 3,835,282 1,330,739 

 

Cash & Cash Equivalents at End of Year $ 2,946,131 $ 4,630,722 $ 3,835,282 

 

SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION: 

 

Cash Paid for Interest $ 138,793 38,439 99,467 

 

Cash Paid for Taxes $ 3,180 106,157 5,371 

SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING & FINANCING ACTIVITIES: 

 

Conversion of accounts payable to long-term note payable $ 0 0 55,000 

 

Unrealized Gain (Loss) on Available-for-Sale Securities, net of tax effect $ 3,035 $ (676,563) $ 816,616 

 

F-7
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, 2011 and 2010 include the accounts of Royale Energy and its proportionate share of the assets, liabilities 

and results of operations. Royale Energy generally retains an ownership interest of approximately 50% in wells it drills with its joint venture projects. Royale Energy 

is the operator of the majority of properties in which it has an ownership interest. In connection with the drilling and operation of wells, the Company receives 

industry standard COPAS fees, which are recorded as supervisory fee income.

Revenue Recognition

Royale Energy recognizes revenues from the sales of oil and natural gas upon transfer of title, net of royalties, in the period of delivery. Settlements for oil and 

natural gas sales can occur up to two months after the end of the month in which the oil and natural gas were produced. We estimate and accrue for the value of 

these sales using information available to us at the time our financial statements are generated.

Royale Energy recognizes revenues from the sale of natural gas in which the Company has an interest with other producers using the entitlements method of 

accounting. Under this method we recognize revenue based on our entitled ownership percentage of sales of natural gas delivered to purchasers. Gas imbalances 

occur when we sell more or less than our entitled ownership percentage of total natural gas production. When we receive more than our entitled share, a liability is 

recorded. Gas imbalances on our production at December 31, 2011, 2010 and 2009, were not significant.

Table of Contents 

 

F-8
Royale Energy enters into turnkey drilling agreements with investors to develop leasehold acreage it has acquired. When Royale Energy sponsors a turnkey drilling 

project for sale, a calculation is made to estimate the pre-drilling costs and the drilling costs. A percentage for each is calculated. The turnkey drilling project is then 

sold to investors who enter into a signed contract with Royale Energy. In this agreement, the investor agrees to share in the pre-drilling costs, which include lease 

costs, and other costs as required so that the drilling of the project can proceed. As stated in the contract, the percentage of the pre-drilling costs that the investor 

contributes is non-refundable, and thus on its financial statements, Royale Energy recognizes these non-refundable payments as revenue since the pre-drilling costs 

have commenced. The remaining investment is held and reported by Royale Energy as deferred revenue from turnkey drilling until drilling is complete. Once drilling 

begins, it is generally completed within 10-30 days. If costs exceed revenues and Royale Energy participates as a working interest owner, Royale’s proportional share 

of the excess is capitalized as the cost of Royale Energy's working interest. If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, 

the deferred funds received would be returned to the investors. Included in cash and cash equivalents are amounts for use in the completion of turnkey drilling 

programs in progress.

Oil and Gas Property and Equipment (Successful Efforts)

Royale Energy accounts for its oil and gas exploration and development costs using the successful efforts method. Leasehold acquisition costs are capitalized. If 

proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Significant undeveloped leases are reviewed periodically 

and a valuation allowance is provided for any estimated decline in value. Cost of other undeveloped leases is expensed over the estimated average life of the leases. 

Cost of exploratory drilling is initially capitalized. In the absence of a determination that proved reserves are found, the costs of drilling such exploratory wells 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-of-production method.

As required by the Extractive Activities Topic of the Financial Accounting Standards Board (FASB), long-lived 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 $4,529,058, $500,144, and $1,935,861, were recorded in 2011, 2010, and 2009 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. Upon abandonment of properties, the reserves are deemed fully depleted and any unamortized costs are recorded in the statement of 

operations under impairment expense.

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 an 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.

Table of Contents 

 

F-9
In 2010, management recorded an impairment of $500,144 in fields where year end reserve values no longer supported the net book values of wells in those 

fields. The majority of this impairment stems from our River Island field in California. An impairment of $233,521 was recorded for this field due to significantly lower 

proved reserves than previously estimated. Royale also had impairments in its Dunnigan Hills, Rio Vista, and Bowerbank fields located in California in the amounts of 

$22,118, $17,931, and $24,680, respectively. These impairments were the result of natural declines and lower reserves than previously estimated. Additionally, Royale 

also had $201,883 in nonviable geological lease and land costs incurred in developing various fields throughout California and Utah that were charged to impairment 

expense.

In 2009, management recorded an impairment of $1,935,861 in fields where year end reserve values no longer supported the net book values of wells in those 

fields. The majority of this impairment, $1,124,293 was recorded in our Moon Canyon field in Utah, were various recently drilled wells had significantly lower proved 

undeveloped reserves than originally estimated. Our Elkhorn Slough field was impaired for $341,098 due to a decline in production and lower proved reserves than 

originally estimated. Royale also had impairments in its East Rice Creek, Rio Vista, and Bowerbank fields in the amounts of $205,173, $74,124, and $71,975, 

respectively. The impairments were the result of natural declines and lower reserves than originally estimated. Additionally, Royale also had $112,165 in nonviable 

geological lease and land costs incurred in developing various fields throughout California that were charged to impairment expense.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and on deposit, and highly liquid debt instruments with maturities of three months or less.

Inventory

Inventory consists of well supplies and spare parts and is carried at lower of cost or market. During 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, 2011 and 2010, net accounts receivable was $1,872,067 and $2,451,047 respectively. At December 31, 2011 and 2010, the Company 

established an allowance for uncollectable accounts of $671,109 and $736,639, 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.

Table of Contents 

 

F-10
Earnings (Loss) Per Share

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

Table of Contents 

 For the Year Ended December 31, 2011 

 

Income

(Numerator) 

Shares

(Denominator) 

Per-Share

Amount 

Basic Earnings Per Share: 

Net loss available to common stock $ (4,104,338) 10,655,258 $ (0.39)

 

 Cumulative effect of accounting change - - - 

 

Diluted Earnings Per Share: 

 Effect of dilutive securities and stock options 

 

Net loss available to common stock $ (4,104,338) 10,655,258 $ (0.39)

 

 For the Year Ended December 31, 2010 

 

Income

(Numerator) 

Shares

(Denominator) 

Per-Share

Amount 

Basic Earnings Per Share: 

Net income available to common stock $ 1,308,028 10,245,033 $ 0.13 

 

 Cumulative effect of accounting change - - - 

 

Diluted Earnings Per Share: 

 Effect of dilutive securities and stock options 850,613 $ (0.01)

 

Net income available to common stock $ 1,308,028 11,095,646 $ 0.12 

 

 For the Year Ended December 31, 2009 

 

Income

(Numerator) 

Shares

(Denominator) 

Per-Share

Amount 

Basic Earnings Per Share: 

 Net loss available to common stock $ (2,197,143) 8,974,786 $ (0.24)

 

Cumulative effect of accounting change 

 

Diluted Earnings Per Share: 

 Effect of dilutive securities and stock options 

 

Net loss available to common stock $ (2,197,143) 8,974,786 $ (0.24)

 

F-11
For the years ended December 31, 2011, and 2009, Royale Energy had dilutive securities of 842,859 and 724,231 respectively. These securities were not included in the 

dilutive earnings per share due to their anti-dilutive 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. In July 2009, the Board of Directors granted a 

total of 17,858 shares of common stock to two directors as compensation for their joint and several guarantee of letter of credit on behalf of the Company. The shares 

vested immediately, but the delivery of the stock certificates was completed in January 2010.

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.

At this time, these new shares will be issued based upon the availability of authorized shares when exercised. These new shares, upon exercise, will not be issued 

from the Company’s Treasury stock holdings.

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.

In January 2000, Royale Energy received 96,000 shares (as adjusted for a later stock split) in a new start up company (the “Settlement Stock”) as part of a settlement in 

an action filed against a former consultant. At the time of the settlement, the value of the Settlement Stock was undeterminable because there was no market for the 

start-up’s stock. In September 2009, issuer of the Settlement Stock conducted an initial public offering of stock, and a market for its shares was established. By 

December 31, 2010, the Company had sold all remaining shares of the Settlement Stock. For the twelve months ended December 31, 2010, the Company recognized a 

realized gain of $907,679 and a related income tax expense of $318,255 from the liquidation of the Settlement Stock. For the same period in 2010, Royale recorded an 

unrealized holding loss of $676,563 in the Other Comprehensive Income (Loss) section of the Statement of Operations. The unrealized holding loss included the 

income tax effect of $323,757.

Table of Contents 

 

F-12
At December 31, 2009, the fair value of the Settlement Stock was $1,000,320, and the shares were classified as available for sale securities. The fair value was 

determined using the number of shares owned as of the last day of the reporting period multiplied by the market price of the Settlement Stock on that day. For the 

year ended December 31, 2009, an unrealized holding gain of $816,616 was recorded in the other comprehensive income (loss) section of the Statement of Operations. 

The unrealized holding gain included the income tax effect of $415,580.

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.

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.

Treasury Stock

The Company records acquisition of its capital stock for treasury at cost. Differences between proceeds for reissuance of treasury stock and average cost are 

charged to retained earnings or credited thereto to the extent of prior charges and thereafter to capital in excess of par value.

Recently Issued Accounting Pronouncements

The Company has reviewed the updates issued by the Financial Accounting Standards Board (FASB) during the year ended December 31, 2011, and have determined 

that the updates are not applicable to the Company.

SEC Rulemaking

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to 

definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the 

management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in 

reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine 

reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make 

up the reporting period. The SEC required companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and 

for annual reports for fiscal years ending on or after December 15, 2009. The adoption of this rule did not have a significant impact on the Company’s financial 

statements.

Table of Contents 

Description 12/31/2011 Level 1 12/31/2010 Level 1

Available for Sale Securities $ 31,027 $ 31,027 $ 0.00 $ 0.00

 

F-13
NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

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

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

Table of Contents 

 2011 2010

Oil and Gas

 Producing properties, including intangible drilling costs $ 23,684,049 $ 25,637,549

 Undeveloped properties 994,687 512,573

 Lease and well equipment 10,284,314 9,750,303

34,963,050 35,900,425

 Accumulated depletion, depreciation and amortization (27,553,222) (26,333,243)

7,409,827 $ 9,567,182

 2011 2010 

Commercial and Other 

 

 Real estate, including furniture and fixtures $ 502,344 $ 502,344 

 Vehicles 151,669 158,250 

 Furniture and equipment 1,307,299 1,285,744 

 1,961,312 1,946,338 

 Accumulated depreciation (1,295,796) (1,255,280)

 

 665,516 691,058 

 

 $ 8,075,344 10,258,240 

 2011 2010 

 

Acquisition - Proved $ 145,746 37,509 

Acquisition- Unproved $ 33,749 137,846 

Development $ 6,493,013 1,379,906 

Exploration $ 538,247 3,335,778 

 

F-14
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 2011 or 2010. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic.

Results of Operations from Oil and Gas Producing and Exploration Activities

The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) for the three years ended December 

31, are as follows:

Table of Contents 

12 Months Ended December 31,

 2011 2010

Beginning balance at January 1 $ 0 $ 0

 

Additions to capitalized exploratory well costs pending the determination of 

proved reserves $ 0 $ 1,408,905

 

Reclassifications to wells, facilities, and equipment based on the 

determination of proved reserves $ 0 $ (1,408,905)

 

Ending balance at December 31 $ 0 $ 0

 2011 2010 2009

Oil and gas sales $ 4,879,397 3,047,201 $ 2,800,557

Production related costs (1,517,920) (1,221,904) (1,415,970)

Lease Impairment (4,529,058) (500,144) (1,935,861)

Depreciation, depletion and amortization (2,362,065) (919,355) (989,716)

Results of operations from producing and

exploration activities $ (3,529,646) 405,798 $ (1,540,990)

Income Taxes (Benefit) (1,024,183) 142,283 (498,746)

 

Net Results $ (2,505,463) 263,515 $ (1,042,244)

 

F-15
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 long-lived assets that 

result from the acquisition, development, and operation of a long-lived asset.

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, 2011 and 2010 Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $4,879,853 and 

$3,866,319, 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).

Table of Contents 

 2011 2010

Asset retirement obligation Beginning of the year

 $ 580,568 $ 514,361

Liabilities incurred during the period 21,173 21,407

Settlements (24,690) (6,017)

Accretion expense 9,266 36,154

Revisions in estimated cash flow (10,705) 14,663

 

 

Asset retirement obligation End of year $ 575,612 $ 580,568

 

F-16
Royale Energy's operations are classified into two principal industry segments. Following is a summary of segmented information for 2011, 2010 and 2009:

Table of Contents 

 

Oil and Gas

Producing

and

Exploration 

Turnkey

Drilling

Services 

 

Total 

Year Ended December 31, 2011 

Revenues from External Customers $ 4,879,397 $ 5,933,065 $ 10,812,462 

 

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 2,264,529 2,264,529 4,529,058 

 

Gain on Sale of Assets 759,763 - 759,763 

 

Income Tax (Benefit) (848,889) (828,882) (1,677,771)

 

Total Assets 19,708,310 1,037,279 20,745,589 

 

Net Income (Loss) $ (2,076,641) (2,027,697) (4,104,338)

 

F-17
Table of Contents 

Year Ended December 31, 2010

Revenues from External Customers $ 3,047,201 $ 7,868,273 $ 10,915,474

Supervisory Fees 670,569 - 670,569

Interest Revenue - 12,397 12,397

Interest Expense 23,307 23,306 46,613

Operating Expenses for Segment Assets 3,921,599 5,100,811 9,022,410

Depreciation, Depletion, and Amortization 873,387 45,968 919,355

Lease Impairment 250,072 250,072 500,144

Gain on Sale of Assets (3,310) - (3,310)

 

Gain on Marketable Securities - 907,679 907,679

 

Income Tax (Benefit) (474,713) 1,180,972 706,259

 

Total Assets 22,629,392 1,191,021 23,820,413

Net Income (Loss) $ (879,192) $ 2,187,220 $ 1,308,028

 

Year Ended December 31, 2009

Revenues from External Customers $ 2,800,557 $ 5,061,804 $ 7,862,361

Supervisory Fees 750,632 - 750,632

Interest Revenue - 12,592 12,592

Interest Expense 50,838 50,837 101,675

 

Expenditures for Segment Assets 3,931,723 4,960,765 8,892,488

Depreciation, Depletion, and Amortization 940,230 49,486 989,716

Lease Impairment 967,931 967,930 1,935,861

Gain (Loss) on Sale of Assets 45,611 - 45,611

 

Income Tax (Benefit) (742,435) (308,966) (1,051,401)

Total Assets 22,386,240 1,178,223 23,564,463

 

Net Income (Loss) $ (1,551,487) $ (645,656) $ (2,197,143)

 

F-18
NOTE 6 - LONG-TERM DEBT

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, a interest coverage ratio not less than 3.00:1, and a bank defined current ratio 

not less than 1:1. The Company was in compliance with, or had obtained a waiver from, the terms of this agreement at December 31, 2011.

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.

Even though the Company’s borrowing base has been reduced by $100,000 a month beginning January 1, 2011, Royale Energy does not classify these commitment 

reductions as a current liability. The underlying line of credit is due February 13, 2013, and the borrowing base is subject to redetermination semiannually by the 

lender or at the request of the borrower. Throughout the year, when new oil and natural gas reserves are discovered, the added reserve value leads to an increase in 

the Company’s borrowing base, and thereby negates any need to paydown any portion of the line of credit during the next twelve months. 

Maturities of long-term debt for years subsequent to December 31, 2011, are as follows:

Table of Contents 

 2011 2010

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, 2011 and 2010, 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. All unpaid principal and 

interest is payable at maturity on February 13, 2013. At December 31, 2011, Royale’s borrowing base with Texas Capital 

Bank was $2,750,000. $ 2,750,000 $ 3,200,000

 

 

 

Total Long Term Debt $ 2,750,000 $ 3,200,000

 

Less Current Maturity $ -

 

Long Term Debt Less Current Portion $ 2,750,000 $ 3,200,000

Year Ended December 31,

2012 $ -

2013 $ 2,750,000

2014 $ -

 

 $ 2,750,000

 

F-19
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, 2011, 2010 and 2009, respectively, are as follows:

The Company had statutory percentage depletion carry forwards of approximately $2,100,000 at December 31, 2011. The depletion has no expiration date. The 

Company also has a net operating loss carry forward of approximately $5,200,000 at December 31, 2011. The first portion of Royale’s net operating loss, $1,100,000, 

will expire in 2027, $1,600,000 will expire in 2028, $1,500,000 will expire in 2029, $300,000 will expire in 2030 with the remaining portion, $700,000, expiring in 2031.

Table of Contents 

 2011 2010 

Deferred Tax Assets (Liabilities): 

 Statutory Depletion Carry Forward $ 839,572 $ 906,804 

 Net Operating Loss 2,145,035 1,852,370 

 Other 375,881 232,909 

 Share-Based Compensation 42,321 0 

 Mark to Market Securities (1,240) 0 

 Capital Loss / AMT Credit Carry Forward 76,410 76,410 

 Charitable Contributions Carry Forward 14,416 33,553 

 Allowance for Doubtful Accounts 263,933 288,768 

 Oil and Gas Properties and Fixed Assets 3,799,419 1,943,967 

 $ 7,557,020 $ 5,334,781 

Valuation Allowance (839,572) 298,194 

Net Deferred Tax Asset (Liability) $ 6,716,208 $ 5,036,587 

 

Deferred Tax Assets: 

 Current $ 661,645 $ 541,442 

 Non-current 6,055,803 4,495,145 

Deferred Tax Liabilities: 

 Current (1,240) - 

 Non-current - 

Net Deferred Tax Asset (Liability) $ 6,716,208 $ 5,036,587 

 

F-20
A reconciliation of Royale Energy's provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2011, 2010 and 

2009, respectively, to pretax income is as follows:

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

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, 

2011, 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 2008 through 2010 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 not have 

the right of redemption at the stockholders' option. During the years ending December 31, 2011, 2010 and 2009, there were no conversions of Series AA Preferred 

stock, and as of December 31, 2011, 2010 and 2009 there were 52,784 shares of Series AA Preferred stock issued and outstanding.

Table of Contents 

 2011 2010 2009

Tax (benefit) computed at statutory rate of 34% $ (1,965,918) $ 684,858 $ (1,104,505)

Increase (decrease) in taxes resulting from:

 

 State tax / percentage depletion / other (256,173) 20,393 (234,255)

 Other non deductible expenses 2,942 1,008 (10,835)

Change in valuation allowance 541,378 - 298,194

Provision (benefit) $ (1,677,771) $ 706,259 $ (1,051,401)

Effective Tax Rate 29.0% 35.1% 32.4%

 2011 2010 2009

 

Current tax provision (benefit) – federal $ - - $ (792,344)

Current tax provision (benefit) – state 3,090 2,432 8,667

Deferred tax provision (benefit) – federal (1,361,898) 686,328 (159,435)

Deferred tax provision (benefit) – state (318,963) 17,499 (108,289)

 

Total provision (benefit) $ (1,677,771) 706,259 $ (1,051,401)

 

F-21
NOTE 9 - COMMON STOCK

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.

In October 2009, the Company entered into an agreement for the private placement of approximately $2 million of common stock and warrants. Funds from the 

offering were used for the drilling and development of several key projects in the Sacramento Basin. The terms of the agreement included the sale of 623,053 shares 

of common stock at $3.21 per share, and a warrant which is immediately exercisable for a period of 5 years to purchase 342,679 shares in the aggregate at $3.53 per 

share. The warrant contains 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 investor has 

also agreed to waive the upward share adjustment portion of the anti-dilution provision that exists in the warrant issued in connection with its 2008 purchase, solely 

in connection with this transaction. The Company has also provided customary registration rights in connection with the transaction, with the stock certificates 

physically delivered to Cranshire Capital, LP in January 2010.

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, 2011 are as follows:

Rental expense for the years ended December 31, 2011, 2010, and 2009, was $371,520, $371,520 and $371,520, respectively.

Table of Contents 

Year Ended

December 31,

2012 $ 391,692

2013 $ 403,873

2014 $ 415,842

2015 $ 246,900

Thereafter $ -

 

 Total $ 1,458,307

 

F-22
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 $23,010, $15,387 and $20,484 for 

their interests for the years ended December 31, 2011, 2010 and 2009, respectively.

NOTE 12 - STOCK COMPENSATION PLAN

During the March 23, 2008 Board of Directors meeting, directors and executive officers of Royale Energy were each granted 45,000 options, a total of 360,000 options, 

to purchase common stock at an exercise or base price of $3.50 per share. These options vested in three parts; the first 120,000vested March 31, 2008, the next 

120,000 vested on March 31, 2009, and the remaining vested on March 31, 2010. The options were granted for a legal life of four years with a service period of three 

years. Royale Energy recorded compensation expense of $74,748 in 2009 and 2010 relating to these options. The total income tax benefit recognized in the income 

statement for these option arrangements was $24,218 in 2009 and $26,209 in 2010.

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 2011, Royale recognized compensation costs of $40,015 and a tax benefit of $11,611 relating to this option grant.

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 risk-free 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.

Table of Contents 

Options 2011 2010 2009

 

Expected volatility 20.84% - -

 Weighted-average volatility 20.84% - -

 

Expected dividends - - -

 

Expected term (months) 60 - -

 

Risk-free rate 2.1% - -

 

F-23
A summary of the status of Royale Energy's stock option plan as of December 31, 2011, 2010 and 2009, and changes during the years ending on those dates is 

presented below:

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, 2009 and 2010, Royale Energy’s stock price was less than the weighted average 

exercise price, and as such the outstanding and exercisable stock options had no intrinsic value. However, 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. These stock options have a weightedaverage remaining contractual term of 2 years 5 months as of December 31, 2011. The fair value of the options vested in 2009 and 2010 was $74,748 for each year.

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. During 2009, Royale recognized $110,332 in compensation expense resulting in a 

$35,748 tax benefit relating to this stock grant. Compensation expense of $104,811 along with a tax benefit relating to this stock grant of $36,749 was recognized by 

the Company during 2010. 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.

In July 2009, the Board of Directors granted a total of 17,858 shares of common stock to two directors as compensation for their joint and several guarantee of letter of 

credit on behalf of the Company. The shares vested immediately and the certificates were delivered in January 2010. Royale recognized share-based compensation 

expense of $37,502 and $12,151 as a tax benefit for this stock grant in the year ended December 31, 2009.

Table of Contents 

2011 2010 2009

Weighted- Weighted- WeightedAverage Average Average

Exercise Exercise Exercise

Shares Price Shares Price Shares Price

Options

 Outstanding at 

Beginning of Year 320,000 $ 3.50 320,000 $ 3.50 320,000 $ 3.50

 Granted 400,000 $ 3.25 - -

 Exercised (45,000) $ 3.44 - -

 Expired or Ineligible - - -

 Outstanding at End of 

Year 675,000 $3.36 320,000 $3.50 320,000 $3.50

 Options Exercisable at 

Year End 475,000 $3.40 320,000 $3.50 200,000 $3.50

Weighted-average Fair 

Value of Options

 Granted During the Year $ 0.21 - -

 

F-24
A summary of the status of Royale Energy's restricted stock grant plans as of December 31, 2011, 2010 and 2009, and changes during the years ending on those dates 

is presented below:

As of December 31, 2011, there was no unrecognized compensation cost related to non-vested share based compensation arrangements granted.

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, 2011, 2010, and 2009 were $60,366, $48,363 and $39,768, 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 2011, 2010 or 2009.

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 88% of its monthly natural gas production to one customer on a month to month basis. Since we are able to sell 

our natural gas to other readily available customers, the loss of any one customer would not have an adverse affect on our overall sales operations.

Table of Contents 

 2011 2010 2009

 Weighted- Weighted- Weighted-

 Average Average Average

 Grant-Date Grant-Date Grant-Date

 Shares Fair Value Shares Fair Value Shares Fair Value

 

Non-vested Shares

 Non-vested at Beginning 

of Year 31,670 $ 3.31 63,335 $ 3.31 95,000 $ 3.31

 Granted - - 17,858 $ 2.10

 Reinstated - - -

 Vested 31,670 $ 3.31 31,665 $ 3.31 49,523 $ 2.87

 Expired or Ineligible - - -

 

 Non-vested at End of 

Year - 31,670 $3.31 63,335 $3.31

 

F-25
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, 2011, and 2010. At December 31, 2010, and 2011, the Company’s non-interest bearing 

accounts were fully insured by the FDIC. At December 31, 2011 and 2010, cash in banks exceeded the FDIC limits by approximately $2.4 million and $3.7 

million, respectively. The Company has not experienced any losses on deposits.

NOTE 16 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED):

Annual Earnings (loss) per share may not equal the sum of the four quarterly amounts due to rounding.

NOTE 17 - 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 is 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. A proposed judgement 

has been submitted to the Court, and we are awaiting entry of the judgement It is uncertain if NFC will appeal this ruling.

Table of Contents 

 First Quarter Second Quarter Third Quarter Fourth Quarter Total Year

2011

Revenues 2,835,156 3,476,645 2,474,228 2,885,019 11,671,048

Operating income (loss) 160,201 440,338 (592,506) (5,651,925) (5,643,892)

Net income (loss) 76,853 259,347 (410,233) (4,030,306) (4,104,339)

Earnings (loss) per share

Diluted $ 0.01 $ 0.02 $ (0.04) $ (0.59) $ (0.39)

Basic $ 0.01 $ 0.02 $ (0.04) $ (0.53) $ (0.39)

 

2010

Revenues $ 1,648,979 $ 4,115,187 $ 2,435,856 $ 3,398,417 $ 11,598,440

Operating income (loss) (586,995) 1,552,109 (294,918) 483,024 1,153,221

Net income (loss) (372,515) 1,075,394 276,200 328,949 1,308,028

Earnings (loss) per share

Diluted $ (0.04) $ 0.10 $ 0.02 $ 0.03 $ 0.12

Basic $ (0.04) $ 0.11 $ 0.03 $ 0.03 $ 0.13

 

F-26
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 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. If 

the case is not dismissed on the jurisdictional motion, Royale intends to answer the complaint and oppose the lawsuit vigorously.

NOTE 18 - SUBSEQUENT EVENTS

On February 17, 2012, the Company entered into a Sales Agreement (the “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 to 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.

The Form S-3 that was filed on December 14, 2011 became effective on February 14, 2012.

Table of Contents 

 

F-27
ROYALE ENERGY, INC.

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Effective for the year ended December 31, 2009, the Securities Exchange Commission and Financial Accounting Standards Board approved revisions designed to 

modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:

We adopted the rules effective December 31, 2009.

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 $10.3 million at December 31, 

2011, based on natural gas prices ranging from $3.90 per MCF to $4.35 per MCF as applied on a field-by-field 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.

Table of Contents 

• Commodity Prices – Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless 

contractual arrangements designate the price to be used.

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

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

will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

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

history.

• Reserves Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees the 

reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves 

estimate.

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

and gas proved reserves

• Non-Traditional Resources – The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method 

of extraction.

 

F-28
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.

Changes in Estimated Reserve Quantities

The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2011, 2010 and 2009 and changes in such quantities 

during each of the years then ended, were as follows:

Table of Contents 

 2011 2010 2009

 

 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF)

Proved developed and undeveloped reserves:

Beginning of period 16,830 5,733,873 15,834 4,617,794 24,635 3,376,568

Revisions of previous estimates 2,205 (1,044,000) 7,501 (529,045) (437) (409,158)

Production (2,264) (1,144,469) (6,505) (603,206) (8,364) (575,995)

Extensions, discoveries and improved 

recovery 1,024,446 2,248,330 - 2,226,380

Purchase of minerals in place

Sales of minerals in place (11,871)

 

Proved reserves end of period 4,900 4,569,850 16,830 5,733,873 15,834 4,617,794

 2011 2010 2009

 

 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF)

Proved developed reserves:

 

Beginning of period 16,830 5,041,179 15,834 4,562,598 24,635 3,184,966

 

End of period 4,900 4,174,050 16,830 5,041,179 15,834 4,562,598

 

F-29
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.

At December 31, 2010, extensions, discoveries and improved recovery amounted to 2,248,330 MCF that were added as a result of drilling five new wells in 2010, four 

exploratory and one developmental. These consisted of 296,781 MCF of proved developed producing reserves on three locations, 1,650,866 MCF of proved 

developed non-producing reserves on two locations and 300,683 MCF of proved undeveloped reserves on one new location. The addition of these proved 

undeveloped reserves along with an adjustment of 336,815 MCF to the previously identified 55,196 MCF location brought the total of proved undeveloped reserves 

to 692,684.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows is presented below for the three years ended December 31, 2011.

The future net cash inflows are developed as follows:

The resulting future net revenue streams are reduced to present value amounts by applying a ten percent discount.

Table of Contents 

 2011 2010 2009

 

 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF)

Proved undeveloped reserves:

 

Beginning of period - 692,694 - 55,196 - 191,602

 

End of period - 395,800 - 692,694 - 55,196

• 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:

2012 $ 821,910

2013 74,500

2014 15,200

Thereafter 269,400

 

Total $ 1,181,010

 

F-30
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 yearend prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.

Table of Contents 

 2011 2010 2009

 

Future cash inflows $ 19,133,280 25.605,730 $ 17,684,460

Future production costs (7,698,630) (7,846,720) (6,013,780)

Future development costs (1,181,010) (2,050,710) (372,190)

Future income tax expense (3,076,065) (4,712,490) (3,389,547)

 

Future net cash flows 7,177,575 10,995,810 7,908,943

 

10% annual discount for estimated timing of cash flows (1,619,267) (2,305,989) (1,647,010)

 

Standardized measure of discounted future net cash flows $ 5,558,308 8,689,821 $ 6,261,933

 

Sales of oil and gas produced, net of production costs $ (1,130,540) (1,135,411) $ (957,988)

Revisions of previous quantity estimates (4,115,420) (119,357) (4,006,942)

Net changes in prices and production costs (1,068,427) (961,284) 815,884

Sales of minerals in place (307,644) - -

Purchases of minerals in place - - -

 

Extensions, discoveries and improved recovery 1,459,973 4,586,632 3,806,933

Accretion of discount 688,468 1,097,831 764,641

 

Net change in income tax 1,342,077 (1,040,523) (126,759)

Net increase (decrease) $ (3,131,513) 2,427,888 $ 295,769

 

F-31
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 2012 through 2014.

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

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:

Table of Contents 

Future development cost of: 2012 2013 2014

Proved developed reserves $ - $ - $ -

Proved non-producing reserves 71,810 74,500 15,200

Proved undeveloped reserves 750,100 - -

 

Total $ 821,910 $ 74,500 $ 15,200

2011 $ 1,560,735

2010 $ 0

2009 $ 0

 

F-32
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 March 14, 2012, 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, 

2011 and 2010, and for the years ended December 31, 2011, 2010, and 2009.

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

March 14, 2012
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 February 22, 2012, in the Annual Report on Form 10-K for the year ended 

December 31, 2011, of the Company and its subsidiaries, to be filed with the Securities and Exchange Commission.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By: /s/ Danny D. Simmons 

Danny D. Simmons, P.E.

President and Chief Operating Officer

Houston, Texas

March 14, 2012

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.
Exhibit 23.3

Source Energy Corp.

3555 Santoro Way, Suite A

San Diego, CA 92130

Phone (858) 259-2271

Fax (858) 259-2273

March 14, 2012

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 08, 2012, in the Annual Report on Form 10-K for the year ended December 31, 2010, 

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
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: March 14, 2012 /s/ Donald H. Hosmer

 Donald H. Hosmer, Co-President and Co-Chief Executive Officer
Exhibit 31.2

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: March 14, 2012 /s/ Stephen M. Hosmer

 Stephen M. Hosmer, Co-President, Co-Chief Executive Officer and Chief Financial Officer
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, 2011 (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: March 14, 2012 By: /s/ Donald H. Hosmer

 Donald H. Hosmer, Co-President and Co Chief Executive Officer
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, 2011 (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: March 14, 2012 By: /s/ Stephen M. Hosmer

 Stephen M. Hosmer, Co-President, Co-Chief Executive Officer and Chief Financial Officer
Exhibit 99.1

February 22, 2012

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, 2011, to the Royale Energy, Inc. (Royale) interest in 

certain oil and gas properties located in California, Louisiana, Oklahoma, and Texas, as listed in the accompanying tabulations. We completed our evaluation on or 

about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the 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.

As presented in the accompanying summary projections, Tables I through IV, we estimate the net reserves and future net revenue to the Royale interest in these 

properties, as of December 31, 2011, to be:

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.

The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves fnight 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. As shown in the Table of Contents, this report includes 

reserves and economics data for each reserves category; these data include a summary projection of reserves and revenue along with one-line summaries of basic 

data, reserves, and economics by lease.

NS•II NETHERLAND, SEWELL

t::i& ASSOCIATES, INC

WORLDWIDE PETROLEUM CONSULTANTS

ENGINEERING • GEOLOGY • GEOPHYSICS • PETROPHYSICS

CHAIRMAN & CEO EXECUTIVE COMMITTEE

C.H. (SCOTT) REES Ill P. SCOTT FROST- DALLAS

PRESIDENT & COO J. CARTER HENSON, JR.- HOUSTON

DANNY D. SIMMONS DAN PAUL SMITH- DALLAS

EXECUTIVE VP JOSEPH J. SPELLMAN- DALLAS

G LANCE BINDER THOMAS J. TELLA II -DALLAS

 Net Reserves Future Net Revenue (M$)

 Oil Gas Present Worth

Category (MBBL) (MMCF) Total at 10%

 

Proved Developed Producing 5.0 1,287.0 2,435.8 1,959.1

Proved Developed Non-Producing 0.0 2,298.1 5,550.8 3,250.3

Proved Undeveloped 0.0 395.8 501.4 253.9

 

Total Proved 5.0 3,980.8 8,488.0 5,463.3

4500 THANKSGIVING TOWER·1601 ELM STREET·DALLAS, TEXAS 75201-

4754 • PH: 214-969-5401 • FAX: 214-969-5411

1221 LAMAR STREET, SUITE 1200 ·HOUSTON, TEXAS 77010-3072 • PH: 713-

654-4950 • FAX: 713-654-4951

nsai@nsai-petro.com 

nethertandsewell.com

 

 
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 and 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-the-month price for each month in the period January through 

December 2011. For oil volumes, the average West Texas Intermediate posted price of $92.71 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 $4.345 per MMBTU is used for the California properties and the average Henry 

Hub spot price of $4.118 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 $103.26 per barrel of oil and $4.101 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 include only 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 Royale's 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.

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.

 

II NETHERLAND, SEWELL

il!i & ASSOCIATES, INC.

 

 
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. 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.

The data used in our estimates were obtained from Royale, other interest owners, various operators of the properties, public data sources, and the 

nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting geoscience, performance, and 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

JMG: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.

 

II NETHERLAND, SEWELL

il!i & ASSOCIATES, INC.

By: /s/ J. Carter Henson, Jr. By: /s/ Mike K. Norton By: /s/ David T. Miller

J. Carter Henson, Jr. Mike K. Norton David T. Miller

Texas P.E. 73964 Texas P.G. 441 Louisiana P.E. 22695

Senior Vice President Senior Vice President Vice President

Date Signed: February 22, 2012 Date Signed: February 22, 2012 Date Signed: February 22, 2012
Exhibit 99.2

Source Energy Corp.

3555 Santoro Way, Suite A

San Diego, CA 92130

February 8, 2012

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, 2011, to the Royale Energy, Inc. (Royale) interest in 

certain oil and gas properties located in Grand County, Utah, as listed in the following tables. It is my understanding that the proved reserves estimated in this 

report constitute approximately 13 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, 2011, to be:

Gas volumes shown above are expressed m thousands of cubic feet (MCF) at standard temperature and pressure basis.

 Net Reserves Future Net Revenue

Category Gas (MCF) Total

Present Worth 

@10%

 

Proved Developed

Non-Producing 589,050 $ 1,765,640 $ 1,421,380

 

Total Proved 589,050 $ 1,765,640 $ 1,421,380

 

 
The estimates shown in this report are for proved developed non-producing reserves. I did not include any proved undeveloped, probable or possible reserves that 

may exist for this property. Currently the properties evaluated in this report are shut-in. Therefore there are no proved developed producing reserves. This report 

does not include any value that could be attributed to interests in undeveloped acreage. Reserves categorization conveys the relative degree of certainty; reserves 

sub categorization 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.

Future gross revenue to the Royale interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes, 

future capital costs, and operating expenses but before consideration of federal income taxes. The future net revenue has been discounted at an annual rate of 10 

percent to determine its present worth. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the 

fair market value of the properties.

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.

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 2011, or $3.90 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 field-level 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 made no investigation or inclusion of potential gas volume and value imbalances resulting from over-delivery or under-delivery to the Royale interest.

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. 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 cost incurred in recovering such reserves may vary from assumptions made while preparing this 

report. Estimates of reserves may increase or decrease as a result of actual reservoir performance, future field operations, market conditions, or changes in 

regulations.

 

 

 
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 generally accepted petroleum engineering and evaluation principles. I used standard engineering and geoscience 

methods, or a combination of methods, such as performance analysis, volumetric analysis, and analogy, that I considered to be appropriate and necessary to 

establish reserves quantities and reserves categorization that conform to SEC definition and guidelines. A substantial portion of these reserves are for behind-pipe 

zones. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and 

reservoir characteristics. In evaluating the information at my disposal concerning this report, I have excluded from consideration all matters as to which the 

controlling interpretation may be legal or accounting, rather than engineering and geoscience. 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.

I have not examined the titles to the properties, or confirmed the actual degree or type of interest owned. The data used in my estimates were obtained from Royale 

Energy, Inc. and public data sources and were accepted as accurate. 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