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EX-32.1 - ROYALE ENERGY FUNDS, INCroyex321.htm
EX-31.2 - ROYALE ENERGY FUNDS, INCroyex312.htm
EX-23.3 - ROYALE ENERGY FUNDS, INCroyex233.htm
EX-31.1 - ROYALE ENERGY FUNDS, INCroyex311.htm
EX-99.2 - ROYALE ENERGY FUNDS, INCroyex992.htm
EX-32.2 - ROYALE ENERGY FUNDS, INCroyex322.htm
EX-23.1 - ROYALE ENERGY FUNDS, INCroyex231.htm
EX-99.1 - ROYALE ENERGY FUNDS, INCroyex991.htm
EX-23.2 - ROYALE ENERGY FUNDS, INCroyex232.htm


SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2009
 
Commission File No. 0-22750

ROYALE ENERGY, INC.
(Name of registrant in its charter)

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

7676 Hazard Center Drive, Suite 1500
San Diego, CA 92108
(Address of principal executive offices)
Issuer's telephone number:     619-881-2800

Securities registered pursuant to Section 12(b) of the Act:
None
Securities to be registered pursuant to Section 12(g) of the Act:
Common Stock, par value $.01 per share
(Title of Class)

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
Yes [  ]; No [X]

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   [X] ;  No [  ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-B is not contained herein, and will not be contained, to the best or registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [   ]

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

Large accelerated filer
[  ]
 
Accelerated filer
[  ]
Non-accelerated filer
[  ]
 
Smaller Reporting Company
[X]

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

At June 30, 2009, the end of the registrant’s most recently completed second fiscal quarter, the aggregate market value of common equity held by non-affiliates was $13,378,774.

At December 31, 2009, 10,225,208 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, 2009, 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.

 
 

 

 

 
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 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
9
Item 3
Legal Proceedings
9
PART II
 
9
Item 5
Market for Common Equity and Related Stockholder Matters
9
 
Dividends
10
 
Recent Sales of Unregistered Securities
10
 
Performance Graph
10
Item 6
Selected Financial Data
11
Item 7
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
11
 
Critical Accounting Policies
11
 
Results of Operations for the Twelve Months Ended Dexcember 31, 2009 as Compared to the Twelve Months Ended December 31, 2008
 
13
 
Results of Operations for the Twelve Months Ended December 31, 2008 as Compared to the Twelve Months Ended December 31, 2007
 
14
 
Capital Resources and Liquidity
16
 
Changes in Reserve Estimates
18
Item 7A
Qualitative and Quantitative Disclosures About Market Risk
19
Item 8
Financial Statements
19
Item 9A
Controls and Procedures
 
 
Disclosure Controls
19
 
Management Report on Internal Control over Financial Reporting
19
 
Changes in Internal Control over Financial Reporting
20
 
Limitations on Effectiveness of Controls
20
PART III
 
20
Item 10
Directors and Executive Officers of the Registrant
20
Item 11
Executive Compensation
21
Item 12
Security Ownership of Certain Beneficial Owners and Management
21
Item 13
Certain Relationships and Related Transactions
21
Item 14
Principal Accountant Fees and Services
21
PART IV
 
21
Item 15
Exhibits and Financial Statement Schedules
22
SIGNATURES
 
23
 
FINANCIAL STATEMENTS
 
F-1

 


 
 

 

ROYALE ENERGY, INC.
PART I
 
Item 1                                Description of Business
 
Royale Energy, Inc. ("Royale Energy") is an independent oil and natural gas producer.  Royale Energy's principal lines of business are the production and sale of natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale Energy.  Royale Energy was incorporated in California in 1986 and began operations in 1988.  Royale Energy's common stock is traded on the NASDAQ Capital Market System (symbol ROYL).  On December 31, 2009, Royale Energy had 22 full time employees.

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

During its fiscal year ended December 31, 2009, Royale Energy continued to explore and develop natural gas properties with a focus in California.  We also own proved developed producing and non-producing reserves of oil and natural gas in Utah, Texas and Louisiana.  In 2009, Royale Energy drilled five wells in northern and central California, three of which were commercially productive wells, two are currently producing, one is awaiting pipeline hookup, and the remaining two were dry holes.  Royale Energy's estimated total reserves increased from approximately 3.6 BCFE (billion cubic feet equivalent) at December 31, 2008 to approximately 4.8 BCFE at December 31, 2009.  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 $11.3 million at December 31, 2009, based on natural gas prices ranging from $2.92 per MCF to $3.87 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, 2009, was estimated to be $6,261,933.  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-29.

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 $5,061,804 for the year ended December 31, 2009, which represents approximately 59% of its total revenues for the year.  In 2008, Royale Energy reported $11,472,065 gross revenues from turnkey drilling operations for the year, representing 60% of Royale Energy's total revenues for that year.

These amounts are offset by drilling expenses and development costs of $2,146,904 in 2009, and $6,015,390 in 2008. 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.

  1
 

 

Approximately 33% of Royale Energy's total revenue for the year ended December 31, 2009, came from sales of oil and natural gas from production of its wells in the amount of $2,800,557.  In 2008, this amount was $6,999,022, which represented 37% of Royale Energy's total revenues.

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

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

Royale Energy also may sell fractional 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 revenue 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-11.  Royale Energy maintains internal records of the expenditure of each investor's funds for drilling projects.

Royale Energy generally operates the wells it completes.  As operator, it receives fees set by industry standards from the owners of fractional interests in the wells and from expense reimbursements.  For the year ended December 31, 2009, Royale Energy earned gross revenues from operation of the wells in the amount of $388,736, representing 4.5% of its total revenues on a consolidated basis for that year.  In 2008, the amount was $392,318, which represented about 2% of total revenues.  At December 31, 2009, Royale Energy operated 52 natural gas wells in California. Royale also owns an interest and operates seven natural gas wells in Utah and has non-operating interests in 17 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.

  2
 

 

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 2009.

Competition, Markets and Regulation
 
Competition

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

Markets

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

Regulation

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

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

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

Royale Energy files quarterly, yearly and other reports with the Securities Exchange Commission.  You may obtain a copy of any materials filed by Royale Energy with the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549, by calling 1-800-SEC-0300.  The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.  Royale Energy also provides access to its SEC reports and other public announcements on its website, http://www.royl.com.

Item 1A                       Risk Factors
 
In addition to the other information contained in this report, the following risk factors should be considered in evaluating our business.

 

 


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

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

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

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

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

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

You should not construe the standardized measure of proved reserves contained in our annual report as the current market value of the estimated proved reserves of oil and gas attributable to our properties. In accordance with Securities and Exchange Commission requirements, we have based the standardized measure of future net cash flows from the standardized measure of proved reserves on the average price during the 12-month period before the ending date of the period covered by the report, whereas actual future prices and costs may vary significantly. The following factors may also affect actual future net cash flows:

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

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

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

In general, the volume of production from oil and gas properties declines as reserves are depleted.  Except to the extent that we acquire properties containing proved reserves or conduct successful development and exploration

 

 

activities, or both, our proved reserves will decline as reserves are produced.  Our future oil and gas production is, therefore, highly dependent upon our ability to find or acquire additional reserves.

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.

 

 

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 December 31, 2009, these individuals owned or controlled the following amounts of Royale Energy common stock, including shares they had the right to acquire on the exercise of outstanding stock options:

Name
Number of Shares (1)
Percent (2), (3)
Donald H. Hosmer
934,709
9.0%
Stephen M. Hosmer (4)
1,175,427
11.5%
Harry E. Hosmer
748,697
7.3%
Total
2,858,833
27.8%

 
(1)
Includes the following options to purchase shares of stock:  Donald H. Hosmer – 45,000, Stephen M. Hosmer – 30,000, and Harry E. Hosmer – 30,000.
 
 
(2)
Based on total of 10,225,208 outstanding shares on December 31, 2009.
 
 
(3)
Calculated pursuant to Rule 13d-3 of the Securities and Exchange Commission.
 
 
(4)
Includes 12,000 shares of stock owned by the minor children of Stephen M. Hosmer.  Mr. Hosmer disclaims beneficial ownership of the shares owned by his children.
 
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 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 2009, Royale Energy drilled five wells in northern and central California, three of which were commercially productive wells, two are currently producing and one is awaiting pipeline hookup.

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 2009, Royale Energy maintained a revolving credit agreement with Texas Capital Bank, N.A..  Under the terms of the agreement, from time to time, 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, 2009, was $2,440,000.  At December 31, 2009, Royale Energy owed $2,440,000 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, 2009, 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 March 4, 2010 and February 11, 2010, 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, 2009, Royale operated 52 wells in California with estimated total proven, developed, and undeveloped reserves at approximately 4.0 bcf, according to Royale’s independently prepared reserve report as of December 31, 2009.

Developed and Undeveloped Leasehold Acreage
 
As of December 31, 2009, Royale Energy owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.

 
Developed
Undeveloped
 
Gross Acres
Net Acres
Gross Acres
Net Acres
California
12,957.58
8,044.49
9,049.00
8,197.54
All Other States
4,800.48
1,849.79
19,871.50
14,118.38
Total
17,758.06
9,894.28
28,920.50
22,315.92

Drilling Activities
 
The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2007, 2008 and 2009.  All wells are located in the Continental U.S., in California, Texas, Louisiana and Utah.

             
Year
Type of Well(a)
 
Gross Wells(e)
Net Wells(b)
   
Total
Producing(c)
Dry(d)
Producing(c)
Dry(d)
             
2007
Exploratory
4
4
0
1.8424
0.0000
 
Developmental
3
2
1
0.6007
0.4613
             
2008
Exploratory
2
1
1
0.4985
0.1238
 
Developmental
5
4
1
1.9441
0.0000
             
2009
Exploratory
3
2
1
0.9715
0.2468
 
Developmental
2
1
1
0.4982
0.5369

 
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.
 

  8
 

 

 
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.

             
   
2009
 
2008
 
2007
Net volume
           
Oil (BBL)
 
8,364
 
11,089
 
14,088
Gas (MCF)
 
575,995
 
714,230
 
791,195
MCFE
 
659,635
 
825,120
 
932,075
             
Average sales price
           
Oil (BBL)
$
52.92
$
95.04
$
$65.02
Gas (MCF)
$
4.09
$
8.32
$
6.56
             
Net production costs and taxes
$
1,415,970
$
2,906,325
$
2,116,977
             
Lifting costs (per MCFE)
$
2.15
$
3.52
$
2.27

Net Proved Oil and Natural Gas Reserves
 
As of December 31, 2009, Royale Energy had proved developed reserves of 4,563 MMCF and total proved reserves of 4,617 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 16 MBBL and total proved oil reserves of 16 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. This lawsuit arose from a dispute over jointly operated property in which Royale is the 75% owner and operator and NFC is a non-operator with a 25% ownership.  NFC disagrees with the Company’s operations and seeks to remove the Company as operator.  As of the date of this filing, both parties have signed a settlement agreement.  However, until the court enters an order dismissing the case, the case remains an active matter.   


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."  On April 1, 2009, Nasdaq notified Royale that it was not in compliance with the requirement that companies listed on the Nasdaq Global Market are required by Marketplace Rule 4450(a)(3) to maintain a minimum of $10 million in stockholders’ equity for continued listing.  Effective July 31, 2009, Royale transferred its securities listing from the Nasdaq Global Market to the Nasdaq Capital Market.  Royale complies with the Capital Market listing requirements.  As of December 31, 2009, 10,225,208 shares of Royale Energy's Common Stock were held by approximately 4,850 stockholders.  The following table reflects high and low quarterly closing sales prices from January 2008 through December 2009. Share prices in this table have been adjusted to give effect to the issuance of stock dividends in 2003, 2004 and 2005, and a stock split in 2004, as described in the next subsection, Dividends.

 

 


 
1st Qtr
 
2nd Qtr
 
3rd Qtr
 
4th Qtr
 
High
Low
 
High
Low
 
High
Low
 
High
Low
2009
3.36
1.40
 
3.77
1.88
 
2.55
1.89
 
3.69
1.99
2008
3.53
2.31
 
13.15
2.63
 
11.36
3.89
 
4.26
2.29

Dividends
 
The Board of Directors did not issue cash or stock dividends in 2009 or 2008.  On January 18, 2007 the Board of Directors authorized the issuance of a cash dividend of $0.05 per share for shareholders of record on February 19, 2007.  The dividend was paid March 5, 2007 in the amount of $397,049.

Recent Sales of Unregistered Securities
 
In March 2008, Royale Energy awarded options to purchase 45,000 shares of common stock at $3.50 per share (the fair market value of Royale’s common stock on the date of grant) to each of its eight directors (a total of 360,000 shares).  In June 2008, three directors exercised their options to acquire a total of 36,844 shares during 2008.  The options were issued and the stock was purchased in reliance on the exemption from registrations 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, 2004, 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, 2004 through December 31, 2009.  The Royale Energy performance figures assume retention of stock dividends in 2003 and 2004 and a stock split issued in the form of a stock dividend in 2004.


 
2004
2005
2006
2007
2008
2009
Royale Energy, Inc.
100
88
48
39
39
37
S & P Composite 500 Stock Index
100
103
117
121
75
92
DJ US Exploration and Production Index
100
164
172
245
145
202


  10
 

 


Item 6                                Selected Financial Data
 
(In thousands, except earnings per share data)
As of December 31,
 
2009
2008
2007
2006
2005
 
Income Statement Data:
           
  Revenues
$  8,626
$  19,174
$ 16,557
$ 24,896
$ 25,643
  Operating Income (Loss)
(3,147)
(14,362)
(3,885)
(3,189)
2,257
 Net Income (Loss)
(2,197)
(8,778)
(2,779)
(2,650)
1,186
 Basic Earnings Per Share
(0.24)
(1.06)
(0.35)
(0.33)
0.15
Balance Sheet Date:
         
  Oil & Gas Properties,
    Equipment & Fixtures
$8,800
$  10,264
$ 23,390
$ 20,526
$ 31,221
  Total Assets
22,564
24,191
32,571
33,715
43,043
  Long Term Obligations
2,954
2,470
6,159
5,757
10,768
  Total Stockholders’ Equity
9,451
7,394
12,385
15,548
18,318


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 sixteen 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 in trust as deferred turnkey drilling until drilling is complete.  Occasionally, drilling is delayed due to the permitting process, or drilling rig availability.  At December 31, 2009 and 2008, Royale Energy had deferred turnkey drilling of $4,979,605 and $4,005,800, respectively.

The primary business segment is oil and gas production.  Northern and central California account for approximately 96% of the company’s successful natural gas production in 2009.  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.

  11
 

 

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.

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 undiscounted cash flows.  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.

12 
 

 

Results of Operations for the Twelve Months Ended December 31, 2009, as Compared to the Twelve Months Ended December 31, 2008
For the year ended December 31, 2009, we had a net loss of $2,197,143, a $6,580,471 improvement when compared to the net loss of $8,777,614 during 2008.  This improvement was due to Company wide efforts to control and reduce costs.  Total revenues from operations for the year in 2009 were $8,625,585, a decrease of $10,548,529, or 55%, from the total revenues of $19,174,114 in 2008.  This decrease in revenues was due to several factors, including the industry wide decline in oil and natural gas commodity prices which affected our oil and natural gas production revenues, and decreased turnkey drilling revenues due to lower direct working interest sales. Although revenues decreased expenses also decreased.  Total costs and expenses fell from $36,084,449 in 2008 to $11,818,065 in 2009, a $24,266,384 or 67% decrease.  The decreased costs and expenses also translated into a 78% decrease in the Company’s loss from operations from $14,362,885 in 2008 to $3,146,869 in 2009, an $11,216,016 decrease.

In 2009, revenues from oil and gas production decreased by 60% to $2,800,557 from $6,999,022 in 2008, due to lower commodity prices received for our oil and natural gas production.  The net sales volume of natural gas for the year ended December 31, 2009, was approximately 575,995 MCF with an average price of $4.09 per MCF, versus 714,230 MCF with an average price of $8.32 per MCF for 2008.  This represents a decrease in net sales volume of 138,235 MCF or 19.4%.  This decrease in production was due to a natural decline in production from existing oil and gas wells.  The net sales volume for oil and condensate (natural gas liquids) production was approximately 8,364 barrels with an average price of $52.92 per barrel for the year ended December 31, 2009, compared to 11,089 barrels at an average price of $95.04 per barrel for the year in 2008.  This represents a decrease in net sales volume of 2,725 barrels, or 24.6%.

Oil and gas lease operating expenses decreased by $1,490,355, or 51.3%, to $1,415,970 for the year ended December 31, 2009, from $2,906,325 for the year in 2008.  This decrease was mainly due to lower workover and plugging and abandonment costs, as cost reduction measures were implemented in 2009.  When measuring lease operating costs on a production or lifting cost basis, in 2009, the $1,415,970 equates to a $2.15 per MCFE lifting cost versus a $3.52 per MCFE lifting cost in 2008, a 39% decrease.

For the year ended December 31, 2009, turnkey drilling revenues decreased $6,410,261 to $5,061,804 in 2009 from $11,472,065 in 2008, or 55.9%.  We also had a $3,868,486 or 64.3% decrease in turnkey drilling and development costs to $2,146,904 in 2009 from $6,015,390 in 2008.  In 2009 we drilled five wells, three exploratory wells and two developmental wells versus two exploratory wells and five developmental wells in 2008.  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 57.6% from 47.6% for the years ended December 31, 2009 and 2008, 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 $1,935,861 and $15,691,348 were recorded in 2009 and 2008, 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 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.  In 2008, $9,508,294 of this impairment was recorded in our Utah field where the weather delays caused lower than expected production to support the proved reserves values that were lower than their current net book values.  The Texas and Gulf Coast fields were impaired $4,950,417, of which $1,936,390 was due to wells which had lower proved reserve values than their current net book values and $3,014,027 was due to previously capitalized lease and land costs which were not expected to be developed within the current year. We impaired two wells in California.  One drilled in 2008 was impaired for $348,376, and the other a workover was impaired $340,129, due to lower reserves.  Two fields in California, the Elkhorn Slough and Bowerbank, were impaired $284,379 and $100,436, respectively due to lower proved reserves than their current book values.

13 
 

 

Additionally in 2009 and 2008, we recorded lease impairments of $112,165 and $827,888, respectively, on various capitalized lease and land costs that were no longer viable.

Bad debt expense for 2009 and 2008 was $255,478 and $567,521, 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 2009, approximately 78% of these expenses stem from one 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 and 2008, we increased the allowance from $973,319 at December 31, 2008 to $1,019,018 at December 31, 2009, for receivables from these Direct Working Interest owners.

The aggregate of supervisory fees and other income was $763,224 for the year ended December 31, 2009, an increase of $60,197 (8.6%) from $703,027 during the year in 2008.  This increase was mainly due to the 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 decreased $3,582 or 1%, to $388,736 in 2009 from $392,318 in 2008.

Depreciation, depletion and amortization expense decreased to $989,716 from $4,148,415 a decrease of $3,158,699 (76.1%) for the year ended December 31, 2009, as compared to 2008.  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 2008 impairments.

General and administrative expenses decreased by $835,646 or 19.1%, from $4,382,462 for the year ended December 31, 2008 to $3,546,816 for the year in 2009.  This decrease was primarily due to reductions in employee related expenses such as salaries, taxes and insurances, implemented in our cost control measures.  Legal and accounting expense decreased to $717,173 for the year, compared to $1,211,989 for 2008, a $494,816 or 40.8% decrease.  This decrease was a result of lower legal fees due to litigation defending property rights in 2008, which culminated in a trial and a successful outcome for the company in April of 2008.

Marketing expense for the year ended December 31, 2009, decreased $350,852 or 30.2%, to $810,147, compared to $1,160,999 for the year in 2008.  Marketing expense usually varies from period to period according to the number of marketing events attended by personnel and their associated costs.  In 2009, our cost containment measures led to decreases primarily in marketing related travel and exhibition costs.

In 2009 and 2008, we recorded gains on the sales of assets of $45,611 and $2,547,450, respectively.  Both gains can be primarily attributable to the sale of our Rio Bravo field located in Kern County, California in September 2008 for $4.75 million.  This resulted in a net gain from the sale of $2,637,203 in 2008 and an additional gain through a reconciling adjustment of $170,713 in 2009.  Additionally, Royale recognized a loss from the sale of its marketable securities of $120,219 in 2009.

During 2009, interest expense decreased to $101,675 from $221,667 in 2008, a $119,992 or 54.1% 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 2009, we had an income tax benefit of $1,051,401 mainly due to our net loss before taxes of $3,248,544.  In 2008, we also had an income tax benefit of $5,806,938 also due to our net loss before taxes of $14,584,552.  The use of percentage depletion created from the current operations, and from utilization of unused percentage depletion carryforwards, results in an effective tax rate less than the normal federal rate of 35% plus the relevant state rates (mostly California, 9.3%).

14 
 

 

Results of Operations for the Twelve Months Ended December 31, 2008, as Compared to the Twelve Months Ended December 31, 2007
For the year ended December 31, 2008, we had a net loss of $8,777,614 compared to the net loss of $2,779,207 during 2007.  The loss was primarily the result of an impairment of $15,691,348 due to a decrease in asset reserve values at year end 2008.  This was mainly due to the industry wide collapse of oil and natural gas prices at year end which reduced reserve values.

Total revenues from operations for the year in 2008 were $19,174,114, an increase of $2,616,715, or 15.8%, from the total revenues of $16,557,399 in 2007.  In 2008 our turnkey drilling revenues increased due to an increase in the number of wells drilled and our natural gas revenues increased due to higher mid-year natural gas and oil prices.  Higher turnkey drilling revenues accounted for 78.9% of the increase.

In 2008, revenues from oil and gas production increased by 14.5% to $6,999,022 from $6,110,092 in 2007, due to higher mid year prices that the industry experienced for a portion of 2008.  The net sales volume of natural gas for the year ended December 31, 2008, was approximately 714,230 MCF with an average price of $8.32 per MCF, versus 791,195 MCF with an average price of $6.56 per MCF for 2007.  This represents a decrease in net sales volume of 76,965 MCF or 9.7%.  This decrease in production was due to a natural decline in production from existing oil and gas wells.  The net sales volume for oil and condensate (natural gas liquids) production was approximately 11,089 barrels with an average price of $95.04 per barrel for the year ended December 31, 2008, compared to 14,088 barrels at an average price of $65.02 per barrel for the year in 2007.  This represents a decrease in net sales volume of 2,999 barrels, or 21.3%.

Oil and gas lease operating expenses increased by $365,889, or 14.4%, to $2,906,325 for the year ended December 31, 2008, from $2,540,436 for the year in 2007.  This increase was mainly due to higher plugging and abandoning and workover costs during the period in 2008 when compared to 2007, as we continue efforts to increase production on some of our existing wells.  When measuring lease operating costs on a production or lifting cost basis, in 2008, the $2,832,413 equates to a $3.43 per MCFE lifting cost versus a $2.27 per MCFE lifting cost in 2007, a 51.1% increase.  Without plugging, abandonment, and workover costs, our lifting costs would have been $1,688,271, or $2.05 per MCFE.

For the year ended December 31, 2008, turnkey drilling revenues increased $2,063,962 to $11,472,065 in 2008 from $9,408,103 in 2007, or 21.9%.  We also had a $1,037,579 or 20.8% increase in turnkey drilling and development costs to $6,015,390 in 2008 from $4,977,811 in 2007.  In 2008, we drilled seven wells and incurred work over expenses for an existing well and we expensed another, previously drilled exploratory dry hole in 2008.  We drilled five developmental wells and two exploratory wells in 2008 versus four exploratory wells and three developmental wells in 2007.  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 47.6% from 47.1% for the years ended December 31, 2008 and 2007, 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 $15,691,348 and $2,106,670 were recorded in 2008 and 2007, respectively.  In 2008 and 2007, we recorded impairments in fields where year end reserve values were less than the net book values of wells in those fields.  In 2008, $9,508,294 of this impairment was recorded in our Utah field where the weather delays caused lower than expected production to support the proved reserves values that were lower than their current net book values.  The Texas and Gulf Coast fields were impaired $4,950,417, of which $1,936,390 was due to wells which had lower proved reserve values than their current net book values and $3,014,027 was due to previously capitalized lease and land costs which were not expected to be developed within the current year. We impaired two wells in California, one drilled in 2008 was impaired for $348,376 and the other a workover was impaired $340,129, due to lower reserves.  Two fields in California, the Elkhorn Slough and Bowerbank, were impaired $284,379 and $100,436, respectively due to lower proved reserves than their current book values.  In 2007, the majority of this impairment, $1,248,843, was recorded in our Bowerbank field in California, where various recently drilled wells had significantly lower proved undeveloped reserves than originally estimated.  The Afton field in California was impaired for $389,946 mainly on acquired wells which ceased producing due to their natural declines and had lower reserves than originally estimated.  Our Texas and Gulf Coast fields were impaired $283,371 due to wells in these

15 
 

 

areas which had lower production and reserves than originally estimated.  Our Elkhorn Slough field was impaired for $148,734 due to lower proved undeveloped reserves than originally estimated.

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 that review in 2008 and 2007, we established an allowance of $973,319 and $546,874, respectively, for receivables from these Direct Working Interest owners.

The aggregate of supervisory fees and other income was $703,027 for the year ended December 31, 2008, a decrease of $336,177 (32.3%) from $1,039,204 during the year in 2007.  This decrease was the result of several factors including the decrease in cost recovery received for use of facilities constructed and placed into service during prior periods as a result of lower production levels.  Supervisory fees are charged in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for reimbursement of expenses associated with the joint accounting for billing, revenue disbursement, and payment of taxes and royalties.  These charges are reevaluated each year and adjusted up or down as deemed appropriate by a published report to the industry by Ernst & Young, LLP, Public Accountants.  Supervisory fees decreased $8,579 or 2.1%, to $392,318 in 2008 from $400,897 in 2007.

Depreciation, depletion and amortization expense increased to $4,148,415 from $3,585,682 an increase of $562,733 (15.7%) for the year ended December 31, 2008, as compared to 2007.  The depletion rate is calculated using production as a percentage of reserves.  This increase in depletion expense was mainly due to the decrease in our oil and gas reserves at year end 2008.

As the result of minor cost cutting measures, general and administrative expenses decreased by $67,630 or 2%, from $4,450,092 for the year ended December 31, 2007 to $4,382,462 for the year in 2008  Legal and accounting expense increased to $1,211,989 for the year, compared to $928,628 for year 2007, a $283,361 or 30.5% increase.  This increase was due to higher legal fees due to litigation defending property rights during 2008 and 2007.

Marketing expense for the year ended December 31, 2008, decreased $294,297 or 20.2%, to $1,160,999, compared to $1,455,296 for the year in 2007.  Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

In September 2008, the company sold its Rio Bravo field located in Kern County, California for $4.75 million, resulting in a net gain from the sale of $2,637,203.  During the first quarter in 2008, we also recorded a loss of $27,823 on the sale of a non-oil and gas asset.  During 2007, we sold our interests in two non oil and gas assets resulting in a loss on sale of $135,396.

During 2008, interest expense increased to $221,667 from $152,547 in 2007, a $69,120 or 45.3% increase.  This was due to an increase in the usage of our bank line of credit.

In 2008, we had an income tax benefit of $5,806,938 mainly due to our net loss before taxes of $14,584,552.  In 2007, we also had an income tax benefit of $1,258,484 also due to our net loss before taxes of $4,037,691.  The use of percentage depletion created from the current operations, and from utilization of unused percentage depletion carryforwards, results in an effective tax rate less than the normal federal rate of 35% plus the relevant state rates (mostly California, 9.3%).

Capital Resources and Liquidity
 
At December 31, 2009, Royale Energy had current assets totaling $8,016,490 and current liabilities totaling $10,159,009, a $2,142,519 working capital deficit.  We had cash and cash equivalents at December 31, 2009 of $3,835,282 compared to $1,330,739 at December 31, 2008.

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.

16 
 

 

We have not, in past years, experienced shortages of funds needed to satisfy our capital expenditure requirements.  We expect that our available credit and cash flows from operations will be sufficient for capital expenditure needs beyond those satisfied from sales of working interests.  We ordinarily fund our operations and cash needs from cash flows generated from operations.  We believe that we have sufficient liquidity for 2010 and do not foresee any liquidity demands that cannot be met from cash flow from operations.

At the end of 2009, our accounts receivable totaled $2,493,108 compared to $3,750,557 at December 31, 2008, a $1,257,449 or 33.5% decrease, primarily due to lower receivables from an industry member participating in wells we drilled at the end of 2008.  At December 31, 2009, our accounts payable and accrued expenses totaled $5,128,987, a decrease of $5,191,200 or 50.3% over the accounts payable at the end of 2008 of $10,320,187.  This decrease was due to applying prepaid drilling remittances to accounts payable in addition to payments made on other trade account payables.

During 2008, Royale Energy maintained a revolving credit agreement with Guaranty Bank, FSB, secured by all of our oil and gas properties, which at December 31, 2008, had outstanding indebtedness of $1,975,974.  In February 2009, the Guaranty Bank loan was repaid and 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 and the Federal Funds rate but in no event less than 5% per year.  On January 15, 2010, Texas Capital Bank re-determined the borrowing base to be $2,440,000 with monthly borrowing base reductions of $80,000 commencing on February 1, 2010.  All unpaid principal and interest is payable at maturity on February 13, 2013.  At December 31, 2009, we had a current borrowing base and outstanding indebtedness on this loan of $2,440,000.

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:
 
Maintain a minimum ratio of earnings before interest, taxes, depreciation and amortization to interest expense of at lest 3.00 to 1.00;
 
 
Maintain a ratio of current assets to current liabilities of at least 1.00 to 1.00; and
 
 
Maintain a tangible net worth as of the close of each fiscal quarter of at least 75% of Royale’s tangible net worth on the loan closing date, plus 75% of positive quarterly net income thereafter.
 
At December 31, 2009, 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, 2009, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.

   
Total Obligations
 
 
2010
 
2011-2012
 
 
2013-2014
 
 
Beyond
                     
Office lease
$
2,208,327
$
369,555
$
772,157
$
819,715
$
246,900
Long-term debt
 
2,490,417
 
50,417
 
-
 
2,440,000
 
-
Total
$
4,698,744
$
419,972
$
772,157
$
3,259,715
$
246,900

Operating Activities.  For the year ended December 31, 2009, cash used by operating activities totaled $884,369 compared to $1,540,924 provided by operating activities for the year in 2008.  This difference in cash was due primarily to a significant decrease in our trade accounts payable and lower direct working interest sales during the year in 2009.  When comparing the 2008 cash provided by operating activities of $1,540,924 to $4,427,012 provided by operating activities for the same period in 2007, there was a $2,886,088 or 65% decrease, which was mainly due to our decrease in deferred income taxes due to our year end loss which provided an income tax benefit for the Company.

17 
 

 

Investing Activities.  For the year ended December 31, 2009, cash used by investing activities was $965,928 compared to $4,689,152 used by investing activities in 2008, a decrease of $3,723,224 or 79%.  The 2008 activity includes $9,865,255, used mainly for oil and gas capital expenditures, along with proceeds of $5,698,911 generated from the sale of our Rio Bravo field during the third quarter of 2008.  The decrease in drilling expenditures during the year in 2009 was due to the drilling of fewer and lower cost wells.  Beginning in July 2008, the Company began to purchase a material amount of equity securities.  Based upon management’s intent for the items, the Company had categorized these as available-for-sale securities.  For the year ended December 31, 2008, we had purchased $633,427 and sold $110,619 in equity securities.  During the third quarter of 2009, the Company liquidated all its equity securities.  For year in 2009, our equity sales and purchases generated $330,545.  In 2007, net cash used by investing activities netted to $8,691,528 for the year in 2007, which included $8,835,180, used mainly for oil and gas capital expenditures, along with proceeds from the sale of non oil and gas assets of $143,652.

Financing Activities.  For the year ended December 31, 2009, cash provided by financing activities was $4,354,840 compared to $629,999 provided by financing activities in 2008, a $3,724,841 difference.  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, due originally to the receipt of the NASDAQ non-compliance notice, see Item 4 Market for Common Equity and Related Stockholder Matters.  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.  In the second quarter of 2008 we received net proceeds of $3,724,999 from the sale of common stock and warrants to one investor in a private placement.  The proceeds were used to pay $2,000,000 to reduce long term debt payments and for working capital.  In 2008, we also received $105,000 from the exercise of stock options.  For 2007, cash provided by financing activities was $735,880 primarily due to an increase in net borrowings on our commercial bank line of credit during the year.  Also in January 2007, the Board of Directors declared a cash dividend of $0.05 per share for shareholders of record on February 19, 2007.  This dividend was paid March 5, 2007, in the amount of $397,049.

Changes in Reserve Estimates
 
Due to recent discoveries, our overall all 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.  See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-29.  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.

In 2008, our estimated proved developed and undeveloped reserve quantities were revised slightly upward by approximately .1 million cubic feet of natural gas mainly due to two California wells which had higher than originally estimated proved producing reserves.  Also in 2008 our estimated proved developed and undeveloped oil reserves were revised upward by approximately 11,900 barrels primarily due to one Texas well which had higher than originally estimated proved producing reserves.

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

 
Oil
Gas
Two existing wells with higher estimated proved producing gas reserves
 
560,627 
One existing well with higher estimated proved producing oil reserves
12,812
 
One existing well with lower estimated proved non-producing gas reserves
 
(351,588)
Increase of proved undeveloped reserves in one existing well
 
111,170 
Reduction of PUD in one existing well
 
(153,661)
     Total
12,812
166,548 

18
 

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

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

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

 
 
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 2009, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline.  In 2009, our natural gas revenues were approximately $2.4 million with an average price of $4.09 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 $240,000.  At our current production levels of oil and natural gas condensate, a 10% increase or decrease in our average price per barrel could potentially increase or decrease our oil and natural gas revenues by approximately $44,000. We currently do not sell any of our natural gas or oil through hedging contracts.

We have a line of credit used in funding purchases of oil and gas assets, meeting drilling schedules and assisting in funding operations.  This line of credit is tied to increases or decreases in the bank prime interest rate.  If the interest rate on our line of credit were to increase 1% or 2% during the year this could potentially add approximately $24,000 to $48,000, respectively, to our interest expense.

Item 8                                Financial Statements and Supplementary Data
 
See pages F-1, et seq., included herein.

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.

19 
 

 

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 2009 fiscal year.  Based on their evaluation, they concluded that our disclosure controls are effective as of December 31, 2009.

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, 2009, which was the end of our fiscal year. Management based its assessment on criteria established in the SEC Commission Guidance Regarding Management’s Report on Internal Control Over Financial Reporting Under Section 13(a) or 15(d) of the Securities Exchange Act of 1934. The guidance sets forth an approach by which management can conduct a top-down, risk-based evaluation of internal control over financial reporting. Management’s assessment included an evaluation of risks to reliable financial reporting, whether controls exist to address those risks and evaluated evidence about the operation of the controls included in the evaluation based on its assessment of risk.

Based on our assessment, management has concluded that our internal control over financial reporting was effective as of the end of the fiscal year to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles. We reviewed the results of management’s assessment with the Audit Committee of our Board of Directors.

This annual report does not include an attestation report of the company's registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the company's registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management's report in this annual report.  Our independent registered public accounting firm, Padgett Stratemann & Co. LLP, audited our consolidated financial statements, and will be required to independently assess the effectiveness of our internal control over financial reporting as of December 31, 2010.

Changes in Internal Control over Financial Reporting
 
No changes in our internal control over financial reporting occurred during the last fiscal quarter of 2009 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.


20 
 

 

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, 2009.

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, 2009.

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, 2009.

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, 2009.

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, 2009.

21
 

 

PART IV
 
Item 15                                Exhibits and Financial Statement Schedules
 
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
Waiver letter regarding adjustment of warrant anti-dilution provisions, incorporated by reference to Exhibit 99.2 of the Company’s Form 8-K filed August 6, 2009.
4.9
Waiver letter regarding adjustment of warrant anti-dilution provisions, incorporated by reference to Exhibit 99.2 of the Company’s Form 8-K filed October 21, 2009.
4.10
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, filed herewith
23.3
Consent of Source Energy, LLC, filed herewith
31.1
Rules 13a-14(a), 115d-14(a) Certification, filed herewith.
31.2
Rules 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

 

22 
 

 

SIGNATURES
 

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

   
Royale Energy, Inc.
     
Date:
March 16, 2010
/s/ Donald H.. Hosmer
   
Donald H.. Hosmer
   
Co-President and Co-Chief Executive Officer
     
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date:
March 16, 2010
/s/ Harry E. Hosmer
Harry E. Hosmer
Chairman of the Board of Directors
Date:
March 16, 2010
/s/ Donald H. Hosmer
Donald H. Hosmer
Director, Co-President, Co-Chief Executive Officer
Date:
March 16, 2010
/s/ Stephen M. Hosmer
Stephen M. Hosmer
Director, Co-President, Co-Chief Executive Officer, Chief Financial Officer and Secretary
Date:
March 16, 2010
/s/ Tony Hall
Tony Hall
Director
Date:
March 16, 2010
/s/ Oscar A. Hildebrandt
Oscar A. Hildebrandt
Director
Date:
March 16, 2010
/s/ Gary Grinsfelder
Gary Grinsfelder
Director
Date:
March 16, 2010
/s/ Gilbert C.L. Kemp
Gilbert C.L. Kemp
Director
Date:
March 16, 2010
/s/ George M. Watters
George M. Watters
Director


  23
 

 

 
ROYALE ENERGY, INC.
 
INDEX TO FINANCIAL STATEMENTS
 
AND SUPPLEMENTARY DATA

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

BALANCE SHEETS DECEMBER 31, 2009 AND 2008 F-3

STATEMENTS OF OPERATIONS F-5

STATEMENTS OF STOCKHOLDERS’ EQUITY F-6

STATEMENTS OF CASH FLOWS F-9

NOTES TO FINANCIAL STATEMENTS F-11



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, 2009 and 2008, and the related statements of operations, stockholders' equity, and cash flows for the years ended December 31, 2009, 2008 and 2007.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Royale Energy, Inc. as of December 31, 2009 and 2008, and the results of its operations and its cash flows for the years ended December 31, 2009, 2008 and 2007, in conformity with accounting principles generally accepted in the United States of America.

We were not engaged to examine management's assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, included in the accompanying Management’s Report on Internal Control over Financial Reporting and, accordingly, we do not express an opinion thereon.




Padgett, Stratemann & Co., L.L.P.
San Antonio, Texas
March 16, 2010


F-2
 
 

 

 
ROYALE ENERGY, INC
BALANCE SHEETS
 
DECEMBER 31, 2009 AND 2008
 

ASSETS



   
2009
 
2008
         
Current Assets
       
Cash and Cash Equivalents
$
3,835,282
$
1,330,739
Accounts Receivable, net
 
2,493,108
 
3,750,557
Prepaid Expenses
 
842,226
 
2,839,735
Deferred Tax Asset
 
0
 
534,698
Available for Sale Securities
 
0
 
218,938
Inventory
 
845,874
 
216,459
 
       
Total Current Assets
 
8,016,490
 
8,891,126
 
       
Other Assets
 
6,946
 
6,946
Deferred Tax Asset - Noncurrent
 
5,740,414
 
5,029,007
         
 
       
Oil And Gas Properties (Successful Efforts Basis)
       
Equipment and Fixtures
 
8,800,293
 
10,263,517
 
       
Total Assets
$
22,564,143
$
24,190,596
 
       

F-3
 
 

 


 
ROYALE ENERGY, INC.
 
BALANCE SHEETS
 
DECEMBER 31, 2009 AND 2008

LIABILITIES AND STOCKHOLDERS' EQUITY


   
2009
 
2008
Current Liabilities:
       
Accounts Payable and Accrued Expenses
$
5,128,987
$
10,320,187
Current Portion of Long-Term Debt
 
50,417
 
0
Deferred Revenue from Turnkey Drilling
 
4,979,605
 
4,005,800
 
       
Total Current Liabilities
 
10,159,009
 
14,325,987
         
Noncurrent Liabilities:
       
Asset Retirement Obligation
 
514,361
 
494,168
Long-Term Debt, Net of Current Portion
 
2,440,000
 
1,975,974
         
Total Noncurrent Liabilities
 
2,954,361
 
2,470,142
         
Total Liabilities
 
13,113,370
 
16,796,129
 
       
Stockholders' Equity
       
         
Common Stock, No Par Value, 20,000,000 and $10,000,000 Shares Authorized; 10,257,827 and 8,538,717 Shares Issued10,225,208 and 8,506,098 Shares Outstanding, Respectively
 
 
 
 
27,246,740
 
 
 
 
23,355,926
         
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)
 
(18,115,452)
 
(15,918,309)
Accumulated Other Comprehensive Loss
 
0
 
(140,053)
         
Total Paid in Capital and Accumulated Deficit                                                                           
 
9,285,302
 
7,451,578
 
       
Less Cost of Treasury Stock, 32,619 Shares
 
(179,376)
 
(179,376)
Paid in Capital, Treasury Stock
 
344,847
 
122,262
         
Total Stockholders' Equity
 
9,450,773
 
7,394,467
         
         
Total Liabilities and Stockholders' Equity
$
22,564,143
$
24,190,596

F-4
 
 

 

ROYALE ENERGY, INC.
STATEMENTS OF OPERATIONS
 
 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007

   
2009
 
2008
 
2007
Revenues:
 
 
 
 
 
 
Sale of Oil and Gas
$
2,800,557
$
6,999,022
$
6,110,092
Turnkey Drilling
 
5,061,804
 
11,472,065
 
9,408,103
Supervisory Fees and Other
 
763,224
 
703,027
 
1,039,204
 
 
 
 
 
 
 
Total Revenues
$
8,625,585
$
19,174,114
$
16,557,399
 
 
 
 
 
 
 
Costs and Expenses:
 
 
 
 
 
 
General and Administrative
 
3,546,816
 
4,382,462
 
4,450,092
Turnkey Drilling & Development
 
2,146,904
 
6,015,390
 
4,977,811
Lease Operating
 
1,415,970
 
2,906,325
 
2,540,436
Lease Impairment
 
1,935,861
 
15,691,348
 
2,106,670
Bad Debt Expense
 
255,478
 
567,521
 
262,532
Legal and Accounting
 
717,173
 
1,211,989
 
928,628
Marketing
 
810,147
 
1,160,999
 
1,455,296
Depreciation, Depletion and Amortization
 
989,716
 
4,148,415
 
3,585,682
 
 
 
 
 
 
 
Total Costs and Expenses
$
11,818,065
$
36,084,449
$
20,307,147
 
 
 
 
 
 
 
Gain (Loss) on Sale of Assets
 
45,611
 
2,547,450
 
(135,396)
             
Income (Loss) from Operations
 
(3,146,869)
 
(14,362,885)
 
(3,885,144)
 
 
 
 
 
 
 
Other Expense:
 
 
 
 
 
 
Interest Expense
 
101,675
 
221,667
 
152,547
 
 
 
 
 
 
 
Income (Loss) Before Income Tax Expense
 
(3,248,544)
 
(14,584,552)
 
(4,037,691)
 
 
 
 
 
 
 
Income Tax Expense (Benefit)
 
(1,051,401)
 
(5,806,938)
 
(1,258,484)
 
 
 
 
 
 
 
Net Income (Loss)
$
(2,197,143)
$
(8,777,614)
$
(2,779,207)
 
 
 
 
 
 
 
Basic Earnings Per Share:
 
 
 
 
 
 
Net Income (Loss) Available To Common Stock
$
(0.24)
$
(1.06)
$
(0.35)
 
 
 
 
 
 
 
Diluted Earnings (Loss) Per Share
$
(0.24)
$
(1.06)
$
(0.35)
             
Other Comprehensive Income
           
    Unrealized Gain(Loss) on Equity Securities
$
352,145
$
(303,870)
$
0
    Less: Reclassification Adjustment for Losses (Gains)
           
        Included in Net Income
 
(120,269)
 
71,994
 
0
             
Other Comprehensive Income (Loss), before tax
 
231,876
 
(231,876)
 
0
             
Income Tax Expense (Benefit) Related to Items     of Other Comprehensive Income
 
91,823
 
(91,823)
 
0
             
Other Comprehensive Income (Loss), net of tax
 
140,053
 
(140,053)
 
0
             
Comprehensive Income (Loss)
$
(2,057,090)
$
(8,917,667)
$
(2,779,207)

F-5
 
 

 


 
ROYALE ENERGY, INC.
STATEMENTS OF STOCKHOLDERS' EQUITY
 
 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007


 
Common Stock
 
Preferred Stock Series AA
               
 
Shares Issued
 
 
Amount
 
Shares Outstanding
 
 
Amount
               
Balance at January 1, 2007
7,951,748
$
$19,511,963
 
57,416
$
167,979
 
             
Stock Options Exercised Adjustment
(2)
 
-
 
-
 
-
               
Cash Dividend $0.05 Per Share
-
 
-
 
-
 
-
               
Stock Award
-
 
-
 
-
 
-
               
Net Income (Loss) for the Year
-
 
-
 
-
 
-
               
Balance at December 31, 2007
7,951,746
$
19,511,963
 
57,416
$
$167,979
 
             
Stock Options Exercised
36,844
 
105,000
 
-
 
-
               
Employee Stock Award Adjustments
(134)
 
-
 
-
 
-
               
Common Stock Private Placement
547,945
 
3,724,998
 
-
 
-
               
Conversion of Preferred AA
2,316
 
13,965
 
(4,632)
 
 (13,965)
               
Stock-Based Compensation –  Stock Options Grant
-
 
-
 
-
 
-
               
Stock – Based Compensation - Restricted Stock Grant
-
 
-
 
-
 
-
               
Available for Sale Securities – Unrealized Loss
-
 
-
 
-
 
-
               
Net Income (Loss) for the Year
-
 
-
 
-
 
-
               
Balance at December 31, 2008
8,538,717
$
23,355,926
 
52,784
$
154,014
               
Common Stock Private Placement
1,175,817
 
2,810,164
 
-
 
-
               
Common Stock Warrant Exercise
511,628
 
1,080,650
 
-
 
-
               
Stock-Based Compensation –  Stock Options Grant
-
 
-
 
-
 
-
               
Stock – Based Compensation - Restricted Stock Grant
31,665
 
-
 
-
 
-
               
Available for Sale Securities – Unrealized Gain
-
 
-
 
-
 
-
               
Net Income (Loss) for the Year
-
 
-
 
-
 
-
               
Balance at December 31, 2009
10,257,827
$
27,246,740
 
52,784
$
154,014


F-6
 
 

 


 
ROYALE ENERGY, INC.
 
STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)
 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007


 
Treasury Stock
   
 
 
 
Shares Acquired
 
 
 
 
Amount
 
Paid in Capital Treasury Stock
 
 
 
 
 
 
Balance at January 1, 2007
35,340
$
(192,052)
$
24,863
           
Stock Options Exercised Adjustment
-
 
-
 
-
           
Cash Dividend $0.05 Per Share
-
 
-
 
-
           
Stock Award
(2,253)
 
$11,040
$
1,712
           
Net Income (Loss) for the Year
-
 
-
 
-
           
Balance at December 31, 2007
33,087
$
(181,012)
$
26,575
           
Stock Options Exercised
-
 
-
 
-
           
Employee Stock Award Adjustments
(468)
 
1,636
 
254
           
Common Stock Private Placement
-
 
-
 
-
           
Conversion of Preferred AA
-
 
-
 
-
           
Stock-Based Compensation – Stock Options Grant
-
 
-
 
74,748
           
Stock-Based Compensation – Restricted Stock Grant
-
 
-
 
20,688
           
Available for Sale Securities – Unrealized Loss
-
 
-
 
-
           
Net Income (Loss) for the Year
-
 
-
 
-
           
Balance at December 31, 2008
32,619
$
(179,376)
$
122,265
           
Common Stock Private Placement
-
 
-
 
-
           
Common Stock Warrant Exercise
-
 
-
 
-
           
Stock-Based Compensation –  Stock Options Grant
-
 
-
 
74,748
           
Stock – Based Compensation - Restricted Stock Grant
-
 
-
 
147,834
           
Available for Sale Securities – Unrealized Gain
-
 
-
 
-
           
Net Income (Loss) for the Year
-
 
-
 
-
           
Balance at December 31, 2009
32,619
$
(179,376)
$
344,847

F-7
 
 

 


 
ROYALE ENERGY, INC.
 
STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)
 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008, AND 2007

   
 
 
 
Accumulated Deficit
 
Accumulated Other Comprehensive Income (Loss)
 
 
 
 
Total
         
 
 
Balance at January 1, 2007
$
(3,964,439)
 
-
$
15,548,314
 
           
Stock Options Exercised Adjustment
 
-
 
-
 
-
             
Cash Dividend $0.05 Per Share
 
(397,049)
 
-
 
 (397,049)
             
Stock Award
 
-
 
-
 
12,752
             
Net Income (Loss) for the Year
 
(2,779,207)
 
-
 
(2,779,207)
             
Balance at December 31, 2007
 
(7,140,695)
 
-
 
 12,384,810
 
           
Stock Options Exercised
 
-
 
-
 
105,000
             
Employee Stock Award Adjustments
 
-
 
-
 
1,890
             
Common Stock Private Placement
 
-
 
-
 
3,724,998
             
Conversion of Preferred AA
 
-
 
-
 
-
             
Stock-Based Compensation –  Stock Options Grant
 
-
 
-
 
74,748
             
Stock-Based Compensation - Restricted Stock Grant
 
-
 
-
 
20,688
             
Available for Sale Securities – Unrealized Loss
 
-
 
(140,053)
 
(140,053)
             
Net Income (Loss) for the Year
 
(8,777,614)
 
-
 
(8,777,614)
             
Balance at December 31, 2008
$
(15,918,309)
$
(140,053)
$
7,394,467
             
Common Stock Private Placement
 
-
 
-
 
2,810,164
             
Common Stock Warrant Exercise
 
-
 
-
 
1,080,650
             
Stock-Based Compensation –  Stock Options Grant
 
-
 
-
 
74,748
             
Stock – Based Compensation - Restricted Stock Grant
 
-
 
-
 
147,834
             
Available for Sale Securities – Unrealized Gain
 
-
 
140,053
 
140,053
             
Net Income (Loss) for the Year
 
(2,197,143)
 
-
 
(2,197,143)
             
Balance at December 31, 2009
$
(18,115,452)
$
-
$
9,450,773

F-8
 
 

 


 
ROYALE ENERGY, INC.
STATEMENTS OF CASH FLOWS
 
 
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007



   
2009
 
2008
 
2007
               
CASH FLOWS FROM OPERATING ACTIVITIES:
         
 
 
Net Income (Loss)
$
(2,197,143)
$
(8,777,614)
$
(2,779,207)
 
Adjustments to Reconcile Net Income to Net Cash (Used in) Provided by
             
Operating Activities:
             
Depreciation, Depletion, and Amortization
 
989,716
 
4,148,415
 
3,585,682
 
Lease Impairment
 
1,935,861
 
15,691,348
 
2,106,670
 
(Gain) Loss on Sale of Assets
 
(165,880)
 
(2,547,450)
 
135,396
 
Realized (Gain) Loss on Equity Securities
 
120,269
 
71,994
 
0
 
Bad Debt Expense
 
255,478
 
567,521
 
262,532
 
Stock-Based Compensation, net of adjustments
 
222,582
 
97,580
 
12,752
 
(Increase) Decrease in:
             
Accounts Receivable
 
1,001,971
 
(227,737)
 
(1,446,583)
 
Prepaid Expenses and Other Assets
 
1,368,094
 
(2,038,402)
 
1,684,996
 
Increase (Decrease) in:
             
Accounts Payable and Accrued Expenses
 
(5,120,590)
 
332,043
 
3,050,651
 
Deferred Revenues - DWI
 
973,805
 
58,703
 
(1,071,164)
 
Deferred Income Taxes
 
(268,532)
 
(5,835,477)
 
(1,114,713)
 
               
Net Cash (Used in) Provided by Operating Activities
 
(884,369)
 
1,540,924
 
4,427,012
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Expenditures For Oil And Gas Properties And
         
 
 
    Other Capital Expenditures
 
(1,430,955)
 
(9,865,255)
 
(8,835,180)
 
Proceeds from Sale of Assets
 
134,482
 
5,698,911
 
143,652
 
Purchase of Equity Securities
 
(8,857)
 
(633,427)
 
0
 
Sale of Equity Securities
 
339,402
 
110,619
 
0
 
               
Net Cash Used in Investing Activities
 
(965,928)
 
(4,689,152)
 
(8,691,528)
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
             
Proceeds from Long-Term Debt
 
7,443,764
 
0
 
6,150,000
 
Principal Payments on Long-Term Debt
 
(6,979,738)
 
(3,200,000)
 
(5,017,071)
 
Dividends Paid
 
0
 
0
 
(397,049)
 
Proceeds from Issuance of Common Stock
 
2,810,164
 
3,724,999
 
0
 
Exercise of Options and Warrants for Cash
 
1,080,650
 
105,000
 
0
 
               
Net Cash Provided by Financing Activities
 
4,354,840
 
629,999
 
735,880
 

F-9
 
 

 


   
2009
 
2008
 
2007
             
Net Increase (Decrease) in Cash and Cash Equivalents
 
2,504,543
 
(2,518,229)
 
(3,528,636)
             
Cash & Cash Equivalents at Beginning of Year
 
1,330,739
 
3,848,968
 
7,377,604
             
Cash & Cash Equivalents at End of Year
$
3,835,282
$
1,330,739
$
3,848,968
             
SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:
           
             
Cash Paid for Interest
 
99,467
 
231,512
 
173,028
             
Cash Paid for Taxes
 
5,371
 
19,338
 
579,080
             
             
SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING & FINANCING ACTIVITIES:
           
             
Conversion of accounts payable to long-term note payable
 
55,000
 
0
 
0
             
Conversion of Series AA Preferred Stock to Common Stock
 
0
 
13,965
 
0
             
Unrealized Loss on Available-for-Sale Securities, net of tax effect
 
140,053
 
(140,053)
 
0


F-10
 
 

 

ROYALE ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
 

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
This summary of significant accounting policies of Royale Energy, Inc. (“Royale Energy” 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, estimated future net cash flows, taxes, and contingencies.

Joint Ventures

The accompanying financial statements as of December 31, 2009 and 2008 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, 2009, 2008 and 2007 were not significant.

Royale Energy enters into turnkey drilling agreements with investors to develop leasehold acreage it has acquired. When Royale Energy sponsors a turnkey drilling project for sale, a calculation is made to estimate the pre-drilling

F-11
 
 

 

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 undiscounted cash flows. Impairment losses of $1,935,861, $15,691,348, and $2,106,670, were recorded in 2009, 2008, and 2007 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 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

F-12
 
 

 

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.

In 2008, Royale Energy recorded an impairment of $15,691,348 in fields where year end reserve values no longer supported net book values of the related wells in those fields.  Moreover, 2008 impairments also include significant impairments of nonviable geological lease and land costs.  The majority of these impairments, $9,508,294, were recorded in our Moon Ridge field in Utah, where recently drilled wells had significantly lower proved reserves than originally estimated.  Royale’s Texas and Gulf Coast fields were impaired $1,936,390 due to lower production, and lower than originally estimated reserves.  In addition, the company also had $3,014,027 in nonviable geological lease and land costs incurred in developing its Gulf Coast and Texas fields with Brigham Exploration Company.  In reviewing these carried costs, management determined Royale Energy would not be able to pursue any additional wells with Brigham where these costs would be allocated.  Royale had impairments in its Dunnigan Hills, Bowerbank, Elkhorn Slough, and Afton fields in the amounts of $55,616, $100,436, $284,379, and $42,828, respectively.   The impairments were the result of natural declines and lower reserves than originally estimated.  Management also impaired its costs relating to it two recently drilled wells in Colusa County and Laris Well field by $348,376 and $340,129, respectively.  These wells, drilled as developmental to existing reserves, produced no gas, and as such, their related costs were impaired.

In 2007, management recorded an impairment of $2,106,670 in fields where year end reserve values no longer supported the net book values of wells in those fields.  The majority of this impairment, $1,248,843 was recorded in our Bowerbank field in California, were various recently drilled wells had significantly lower proved undeveloped reserves than originally estimated.  The Afton field in California was impaired for $389,946 mainly on acquired wells which ceased producing due to their natural declines and had lower reserves than originally estimated.  Our Texas and Gulf Coast fields were impaired $283,371 due to wells in these areas that had been drilled in the last few years which had significantly lower production and reserves than originally estimated.  Our Elkhorn Slough field was impaired for $148,734 due to lower proved undeveloped reserves than originally estimated

Reclassification

Certain items in the financial statements have been reclassified to maintain consistency and comparability for all periods presented herein.  The company has determined that certain General and Administrative charges are presented more fairly as Bad Debt Expenses, and certain Geological and Geophysical Expenses are presented more fairly as Lease Operating costs.  The reclassification is reflected in all years presented.

Cash and Cash Equivalents

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

Inventory

Inventory consists of well supplies and spare parts and is carried at lower of cost or market.

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, 2009 and 2008, net accounts receivable was $2,493,108 and $3,750,557 respectively. At December 31, 2009 and 2008, the Company established an allowance for uncollectable accounts of $1,019,018 and $973,319, respectively for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

F-13
 
 

 


Equipment and Fixtures

Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred. Gains or losses on dispositions of property and equipment, other than oil and gas, are reflected in operations.
 
 
Earnings (Loss) Per Share
 
Basic and diluted earnings (loss) per share are calculated as follows:

   
For the Year Ended December 31, 2009
       
   
Income
(Numerator)
 
Shares
(Denominator)
 
Per-Share
Amount
Basic Earnings Per Share:
           
Net income 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 income available to common stock
$
(2,197,143)
 
8,974,786
$
(0.24)
             
             
   
For the Year Ended December 31, 2008
       
   
Income
(Numerator)
 
Shares
(Denominator)
 
Per-Share
Amount
Basic Earnings Per Share:
           
Net income available to common stock
$
(8,777,614)
 
8,246,972
$
     (1.06)
             
  Cumulative effect of accounting change
           
             
Diluted Earnings Per Share:
           
  Effect of dilutive securities and stock options
           
             
Net income available to common stock
$
(8,777,614)
 
8,246,972
$
 (1.06)
             

F-14
 
 

 


             
   
For the Year Ended December 31, 2007
       
   
Income
(Numerator)
 
Shares
(Denominator)
 
Per-Share
Amount
Basic Earnings Per Share:
           
  Net income available to common stock
$
(2,779,207)
 
7,917,543
$
   (0.35)
             
Cumulative effect of accounting change
           
             
Diluted Earnings Per Share:
           
  Effect of dilutive securities and stock options
           
             
Net income available to common stock
 
$(2,779,207)
 
7,917,543
 
$    (0.35)

For the years ended December 31, 2009, 2008, and 2007, Royale Energy had dilutive securities of 724,231, 43,700, and 28,708, respectively.  These securities were not included in the dilutive earning 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 14.  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.

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 enterprise’s
 
F-15
 

 
financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is more likely than not to be sustained upon examination, then an enterprise would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. As discussed in Note 7, the adoption did not materially affect our financial position or results of operations.

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.
During the third quarter of 2009, the Company liquidated its holdings of available for sale securities.  At that time, Royale recognized $140,053 as other comprehensive income, which included an income tax expense of $91,823.

At December 31, 2008, Royale Energy reported a fair value of $218,938 relating to available for sale securities.  For the purposes of identifying related costs to its available for sale securities, the Company uses a specific identification method.  On December 31, 2008, the total cost for those securities amounted to $450,813.  An unrealized holding loss of $140,053 was recorded in the equity’s other comprehensive loss section.  The unrealized holding loss included an income tax benefit of $91,823.

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.

In 2008, Royale Energy reported the fair value of $218,938 in available for sale securities.  The fair value was determined using the number of shares owned as of December 31, 2008, multiplied by the market price of those securities on December 31, 2008. At December 31, 2009, Royale no longer owned any available for sale securities.
 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, 2009, Royale Energy quoted prices in active markets for identical assets when determining the fair value measurements at the reporting date.
 
 
Description
12/31/2009
Level 1
12/31/2008
Level 1
Available for Sale Securities
$0
$0
$218,938
$218,938

 
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 adopted the Subsequent Events Topic of the FASB Accounting Standards Codification. It establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. The Topic sets forth (1) The period after the balance sheet date during which
 
F-16
 

 
management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) The circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and (3) The disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The Topic is effective for interim or annual financial periods ending after June 15, 2009. The adoption of this standard did not have a significant impact on the Company’s interim financial information.

In June 2009, the Financial Accounting Standards Board issued Generally Accepted Accounting Principles Topic of the FASB Accounting Standards Codification. The Topic sets forth that the Financial Accounting Standards Board Accounting Standards Codification is the exclusive authoritative reference for nongovernmental U.S. GAAP for use in financial statements issued for interim and annual periods ending after September 15, 2009, except for SEC rules and interpretive releases, which also are authoritative GAAP for SEC registrants. The change was established by FASB Statement of Financial Accounting Standards No. 168 “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (FAS 168), which divides nongovernmental U.S. GAAP into the authoritative Codification and guidance that is nonauthoritative, doing away with the previous four-level hierarchy. The Topic is effective for financial statements for interim or annual reporting periods ending after September 15, 2009. The Topic was not intended to change or alter existing GAAP, and the Company’s adoption did not have any impact on its consolidated financial statements other than to modify certain existing disclosures. Upon adoption, the Company began to use the new guidelines and numbering system prescribed by the Topic when referring to GAAP in the third quarter of fiscal year 2009.

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 will require 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.


F-17
 
 

 


 NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES
 
Oil and gas properties, equipment and fixtures consist of the following at December 31:

   
2009
 
2008
 
2007
Oil and Gas
     
 
 
 
 
     
 
 
 
  Producing properties, including intangible drilling costs
$
23,746,696
$
23,875,461
$
32,479,353
  Undeveloped properties
 
570,831
 
1,102,317
 
2,974,647
  Lease and well equipment
 
9,251,307
 
9,081,305
 
8,069,725
 
 
33,568,834
 
34,059,083
 
43,523,725
  Accumulated depletion, depreciation and amortization
 
(25,512,869)
 
(24,612,940)
 
(21,098,694)
 
           
 
$
8,055,965
$
9,446,143
$
22,425,031
 
           
             
             
Commercial and Other
           
 
           
  Real estate, including furniture and fixtures
 
502,344
 
$503,344
 
503,344
  Vehicles
 
255,496
 
313,460
 
313,460
  Furniture and equipment
 
1,258,439
 
1,232,647
 
1,200,852
   
2,016,279
 
2,049,451
 
2,017,656
  Accumulated depreciation
 
(1,271,951)
 
(1,232,077)
 
(1,052,946)
 
           
 
 
744,328
 
817,374
 
964,710
 
           
 
$
8,800,293
$
10,263,517
$
23,389,741
 
     
 
 
 

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

   
2009
 
2008
 
2007
 
       
 
 
Acquisition - Proved
$
4,355
$
288,569
$
1,690
Acquisition- Unproved
$
16,803
$
 (218,533)
$
1,060,983
Development
$
1,471,436
$
9,701,556
$
3,441,517
Exploration
$
2,725,885
$
2,047,211
$
9,763,490
             
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 2009 or 2008. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic.

F-18
 
 

 


 
12 Months Ended December 31,
   
2009
 
2008
Beginning balance at January 1                                                      
$
0
$
0
         
Additions to capitalized exploratory well costs  pending the determination of proved reserves
 
$
 
953,082
 
$
 
497,889
         
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
 
$
 
(953,082)
$
 
(497,889)
         
Ending balance at December 31
$
0
$
0

Results of Operations from Oil and Gas Producing and Exploration Activities

The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) for the three years ended December 31, are as follows:

   
2009
 
2008
 
2007
 
 
 
 
 
 
 
Oil and gas sales
$
2,800,557
$
6,999,022
$
6,110,092
Production related costs
 
(1,415,970)
 
(2,906,325)
 
(2,540,436)
Lease Impairment
 
(1,935,861)
 
(15,691,348)
 
(2,106,670)
Depreciation, depletion and amortization
 
(989,716)
 
(4,148,415)
 
(3,585,682)
 
 
     
 
 
Results of operations from producing and
 
     
 
 
exploration activities
$
(1,540,990)
$
(15,747,066)
$
(2,122,696)
Income Taxes (Benefit)
 
(498,746)
 
(6,269,004)
 
(732,330)
             
Net Results
$
(1,042,244)
$
(9,478,062)
$
(1,390,366)
 
 
   
 
 
 
In September 2008, Royale Energy sold its Rio Bravo field located in Kern County, California for approximately $4.75 million to Occidental Petroleum of Elk Hills Inc, resulting in a net gain from the sale of $2,637,203. The proceeds from this sale were used in drilling additional natural gas wells as well as in the operations of the company.

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.

   
2009
 
2008
Asset retirement obligation Beginning of the year
       
 
$
494,168
$
402,278
Liabilities incurred during the period
 
2,903
 
14,808
Settlements
 
0
 
(21,571)
Accretion expense
 
32,293
 
27,683
Revisions in estimated cash flow
 
(15,003)
 
70,970
         
         
Asset retirement obligation End of year
$
514,361
$
494,168

 
F-19
 

 
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, 2009 and 2008 Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $4,979,605 and $4,005,800, respectively, as a current liability.

NOTE 5 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS
 
Royale Energy identifies reportable segments by product and country, although Royale Energy currently does not have foreign country segments. Royale Energy includes revenues from both external customers and revenues from transactions with other operating segments in its measure of segment profit or loss. Royale Energy also includes interest revenue and expense, DD&A, and other operating expenses in its measure of segment profit or loss.

The accounting policies of the reportable segments are the same as those described in the Summary of Significant Accounting Principles (see Note 1).

Royale Energy's operations are classified into two principal industry segments. Following is a summary of segmented information for 2009, 2008 and 2007:

   
Oil and Gas Producing and Exploration
 
 
Turnkey Drilling Services
 
 
 
 
Total
Year Ended December 31, 2009
 
 
 
     
Revenues from External Customers
 $
2,800,557
$
5,061,804
$
7,862,361
 
 
         
Supervisory Fees
 
750,632
 
0
 
750,632
 
 
         
Interest Revenue
 
0
 
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
 
1,935,861
 
0
 
1,935,861
 
 
         
Gain on Sale of Assets
 
45,611
 
0
 
45,611
             
Income Tax (Benefit)
 
(525,701)
 
(525,700)
 
(1,051,401)
             
Total Assets
 
22,564,143
 
0
 
22,564,143
 
 
         
Net Income (Loss)
 $
(2,736,151)
$
539,008
$
(2,197,143)


F-20
 
 

 


   
Oil and Gas Producing and Exploration
 
 
Turnkey Drilling Services
 
 
 
 
Total
Year Ended December 31, 2008
 
 
 
     
Revenues from External Customers
 $
6,999,022
$
11,472,065
$
18,471,087
 
 
         
Supervisory Fees
 
613,338
 
-
 
613,338
 
 
         
Interest Revenue
 
-
 
89,689
 
89,689
 
 
         
Interest Expense
 
110,834
 
110,833
 
221,667
 
 
         
Expenditures for Segment Assets
 
6,207,052
 
10,037,634
 
16,244,686
 
 
         
Depreciation, Depletion, and Amortization
 
3,940,994
 
207,421
 
4,148,415
 
 
         
Lease Impairment
 
15,691,348
 
-
 
15,691,348
 
 
         
Gain on Sale of Assets
 
2,547,450
 
-
 
2,547,450
             
Income Tax (Benefit)
 
(2,903,469)
 
(2,903,469)
 
(5,806,938)
             
Total Assets
 
24,190,596
 
-
 
24,190,596
 
 
         
Net Income (Loss)
$
(12,886,949)
$
4,109,335
$
(8,777,614)
 
 
 
 
 
 
 
Year Ended December 31, 2007
 
 
 
 
 
 
Revenues from External Customers
$
6,110,092
$
9,408,103
$
15,518,195
 
 
         
Supervisory Fees
 
847,603
     
847,603
 
 
         
Interest Revenue
 
95,800
 
95,801
 
191,601
 
 
         
Interest Expense
 
76,274
 
76,273
 
152,547
             
Expenditures for Segment Assets
 
5,713,881
 
8,900,914
 
14,614,795
 
 
         
Depreciation, Depletion, and Amortization
 
3,406,398
 
179,284
 
3,585,682
 
 
         
Lease Impairment
 
2,106,670
 
-
 
2,106,670
 
 
         
Gain (Loss) on Sale of Assets
 
(67,698)
 
(67,698)
 
(135,396)
             
Income Tax  (Benefit)
 
(629,242)
 
(629,242)
 
(1,258,484)
 
 
         
Total Assets
$
32,571,374
$
 
$
32,571,374
             
Net Income (Loss)
$
(3,688,184)
$
908,977
$
(2,779,207)
 
 
 
 
 
 
 


F-21
 
 

 


NOTE 6 - LONG-TERM DEBT
 
   
2009
 
2008
         
Revolving line of credit secured by oil and gas properties, with a maximum available of $5,375,974 at December 31, 2008, issued by Guaranty Bank FSB. for the purposes of refinancing Royale’s existing debt and to fund development, exploration and acquisition activities as well as other general corporate purposes.  The agreement was entered into on January 21, 2003.  Interest is at Guaranty Bank’s “Base Rate” plus 0.50%, resulting in a rate of 3.75% at December 31, 2008, payable monthly with borrowing base reductions of $200,000 commencing on January 1, 2008.  As part of this agreement, Guaranty Bank has issued letters of credit in the amount of $774,025 on behalf of the Company to various agencies.  All unpaid principal and interest was paid on February 13, 2009.
$
0
$
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,975,974
         
Revolving line of credit secured by oil and gas properties, with a maximum available of $14,250,000 at December 31, 2009, 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, 2009, payable monthly with borrowing base reductions of $80,000 commencing on February 1, 2010.  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, 2009, Royale’s borrowing base with Texas Capital Bank was $2,440,000.
$
2,440,000
$
0
         
An unsecured Note payable was issued to Von Fletcher Trucking Inc. for $55,000 for the purposes of financing services performed by the vendor.  The promissory note was entered into on September 30, 2009, with an interest rate of 10%.  Monthly principal payments of $4,583 plus any accrued interest will commence for twelve months beginning January 1, 2010.
$
50,417
$
0
         
Total Long Term Debt
$
2,490,417
$
1,975,974
         
Less Current Maturity
$
50,417
 
0
         
Long Term Debt Less Current Portion
$
2,440,000
$
1,975,974
         
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

F-22
 
 

 

less than 1:1. The Company was in compliance with, or had obtained a waiver from, the terms of this agreement at December 31, 2009.

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 $80,000 a month beginning February 1, 2010, 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, 2009, are as follows:

Year Ended December 31,
 
 
2010
$
50,417
2011
$
0
2012
$
0
2013
$
2,440,000
 
$
2,490,417

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, 2009, 2008 and 2007, respectively, are as follows:
   
2009
 
2008
 
2007
Deferred Tax Assets (Liabilities):
 
 
 
 
 
 
  Statutory Depletion Carry Forward
$
894,590
$
902,529
$
689,985
  Net Operating Loss
 
1,740,853
 
1,094,343
 
421,982
  Other
 
171,727
 
103,979
 
8,024
  Mark to Market Securities
 
0
 
91,823
 
0
  Capital Loss / AMT Credit Carry Forward
 
76,410
 
44,117
 
18,915
  Charitable Contributions Carry Forward
 
6,495
 
6,397
 
383
 Allowance for Doubtful Accounts
 
367,878
 
332,499
 
209,179
 Oil and Gas Properties and Fixed Assets
 
2,780,655
 
2,988,018
 
(1,577,216)
 
$
6,038,608
$
5,563,705
$
(228,748)
Valuation Allowance
 
298,194
 
-
 
(134,847)
Net Deferred Tax Asset (Liability)
$
5,740,414
$
5,563,705
$
 (363,595)
             
Deferred Tax Assets:
           
  Current
$
0
$
534,698
$
217,586
  Non-current
 
5,740,414
 
5,029,007
 
0
Deferred Tax Liabilities:
           
  Current
 
0
 
0
 
0
 Non-current
 
0
 
0
 
(581,181)
Net Deferred Tax Asset (Liability)
$
5,740,414
$
5,563,705
$
 (363,595)
 
 
 
       

The Company had statutory percentage depletion carry forwards of approximately $2,300,000 and $2,300,000 at December 31, 2009 and 2008, respectively.  The depletion has no expiration date.  The Company also has a net operating loss carry forward of approximately $ 4,200,000 and $2,800,000 at December 31, 2009 and 2008,

F-23
 
 

 

respectively.  The first portion of Royale’s net operating loss, $1,100,000, will expire in 2027, $1,600,000 will expire in 2028 with the remaining portion, $1,500,000, expiring in 2029.

A reconciliation of Royale Energy's provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2009, 2008 and 2007, respectively, to pretax income is as follows:


   
2009
 
2008
 
2007
 
           
Tax (benefit) computed at statutory rate
$
(1,104,505)
$
 (4,958,749)
$
 (1,372,815)
 
           
Increase (decrease) in taxes resulting from:
           
             
  State tax / percentage depletion / other
 
(234,255)
 
(727,256)
 
           (23,503)
  Other non deductible expenses
 
(10,835)
 
13,941
 
                 2,987
Change in valuation allowance
 
298,194
 
(134,874)
 
           134,847
Provision (benefit)
$
(1,051,401)
$
 (5,806,938)
$
 (1,258,484)
 
           
Effective Tax Rate
 
32.4%
 
39.6%
 
    31.2%
 
 
The components of the Company’s tax provision are as follows:

   
2009
 
2008
 
2007
             
Current tax provision (benefit) – federal
$
(792,344)
$
20,667
$
 (171,795)
Current tax provision (benefit) – state
 
8,667
 
7,872
 
28,023
Deferred tax provision (benefit) – federal
 
(159,435)
 
(4,729,030)
 
(1,120,479)
Deferred tax provision (benefit) – state
 
(108,289)
 
(1,106,447)
 
5,767
             
Total provision (benefit)
$
(1,051,401)
$
(5,806,938)
$
(1,258,484)
             

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, 2009, 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 2002 through 2009 remain open to examination by the taxing jurisdictions in which we file income tax returns.

NOTE 8 - REDEEMABLE PREFERRED STOCK
 
In 1993, Royale Energy's Board of Directors authorized the issuance of 259,250 shares of Series A Convertible Preferred Stock. The Stock is convertible any time at the basic conversion rate of one share of common stock for two shares of Series A Convertible Preferred Stock, subject to adjustment.

There were no Series A Convertible Preferred Stock conversions in 2009, 2008, or 2007.

NOTE 9 - SERIES AA PREFERRED STOCK
 
In April 1992, Royale Energy's Board of Directors authorized the sale of Series AA Convertible Preferred Stock.  Holders of Series AA Convertible Preferred Stock have dividend, conversion and preference rights identical to Series A Convertible Preferred Stockholders.  The Series AA Convertible Preferred Stock does not have the right of redemption at the stockholders' option.    As of December 31, 2007, there were 57,416 shares issued and outstanding.  In 2008, a Preferred AA stockholder was issued 2,316 shares of common stock in exchange for 4,632 share of Series AA Preferred stock resulting in 52,784 shares of Series AA Preferred stock issued and outstanding as

F-24
 
 

 

of December 31, 2008.  During the year ending December 31, 2009, there were no conversions of Series AA Preferred stock, and as of December 31, 2009 there were 52,784 shares of Series AA Preferred stock issued and outstanding.

NOTE 10 - COMMON STOCK
 
On January 18, 2007 the Board of Directors authorized the issuance of a cash dividend of $0.05 per share for shareholders of record on February 19, 2007.  The dividend was paid March 5, 2007 in the amount of $397,049.

In 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.  The net proceeds from the private placement 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 6 months and 1 day after the closing date (which date of exercisability will be 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.
During September and October 2009, 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.

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 11 - 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, 2009 are as follows:

F-25
 
 

 


Year Ended
   
December 31,
   
 
   
2010
$
369,555
2011
$
380,465
2012
$
391,692
2013
$
403,873
2014
$
415,842
Thereafter
$
246,900
     
 Total
$
2,208,327
 
   

Rental expense for the years ended December 31, 2009, 2008, and 2007 was $371,520, $370,620, and $403,497, respectively.

NOTE 12 - RELATED PARTY TRANSACTIONS
 
Significant Ownership Interests
 
Donald H. Hosmer, Royale Energy’s co-president, owns 9.0% 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 and chief financial officer, owns 11.5% 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 7.3% 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 $20,484, $38,326 and $21,759 for their interests for the years ended December 31, 2009, 2008 and 2007, respectively.

NOTE 13 - 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 are to be vested in three parts; the first 120,000 have vested March 31, 2008, the next 120,000 have vested on March 31, 2009, and the remaining will vest 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 2008 and 2009 relating to these options. The total income tax benefit recognized in the income statement for these option arrangements was $29,600 in 2008 and $24,218 in 2009.

The fair value of the options was calculated using the Black-Scholes option pricing method.  Since there is 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.

F-26
 
 

 


Options
 
2009
 
2008
 
2007
             
Expected volatility
 
               -
 
40%
 
               -
             
Weighted-average volatility
 
               -
 
40%
 
               -
             
Expected dividends
 
               -
 
               -
 
               -
             
Expected term (months)
 
               -
 
48
 
               -
             
Risk-free rate
 
               -
 
2.89%
 
               -

A summary of the status of Royale Energy's stock option plan as of December 31, 2009, 2008 and 2007, and changes during the years ending on those dates is presented below:

 
2009
 
2008
 
2007
   
 
 
Weighted-
 
Weighted-
 
Weighted-
 
 
Average
 
Average
 
Average
 
 
Exercise
 
Exercise
 
Exercise
 
Shares
Price
Shares
Price
Shares
Price
 
       
 
 
Options
       
 
 
  Outstanding at Beginning of Year
320,000
$3.50
-
 
-
 -
  Granted
 -
 
360,000
$3.50
   
  Exercised
-
 
(40,000)
$3.50
 -
 
  Expired or Ineligible
-
 
-
 
 -
 
 
           
  Outstanding at End of Year
320,000
$3.50
320,000
$3.50
  -
 -
 
           
  Options Exercisable at Year End
200,000
$3.50
80,000
$3.50
 -
 -
 
       
 
 
Weighted-average Fair Value of Options
       
 
 
  Granted During the Year
-
 
$224,244
 
-
 
 
   
 
 
 
 
The weighted-average grant-date fair value of options granted during 2008 was $0.62 per share, and the fair value of the options vested in 2008 was $74,748.  The total intrinsic value of options exercised during 2008 was $220,846.  At December 31, 2008 and 2009, 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.  These stock options have a weighted-average remaining contractual term of 28 months as of December 31, 2009.  The fair value of the options vested in 2009 was $74,748

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; 31,667 or 63,334 shares, depending on Royale’s stock price, will vest on November 30, 2010 and 2011.  The first 31,665 shares vested on November 30, 2009.  Royale has recognized share-based compensation expense of $20,688 and $8,192 as a tax benefit in 2008 relating to this grant.  During 2009, Royale recognized $110,332 in compensation expense resulting in a $35,748 tax benefit relating to this stock grant.

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 has recognized share-based compensation expense of $37,502 and $12,151 as a tax benefit for this stock grant.

F-27
 

 
A summary of the status of Royale Energy's restricted stock grant plans as of December 31, 2009, 2008 and 2007, and changes during the years ending on those dates is presented below:

 
2009
   
2008
   
2007
 
   
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
95,000
$3.31
 
                -
   
               4,622
$5.66
  Granted
17,858
$2.10
 
95,000
$3.31
 
-
 
  Reinstated
-
   
-
   
-
 
  Vested
49,523
$2.87
 
-
   
2,253
 
  Expired or Ineligible
-
   
-
   
 2,369
 
                 
  Non-vested at End of Year
63,335
$3.31
 
95,000
$3.31
 
-
 

As of December 31, 2009, there was $161,362 of total unrecognized compensation cost related to non-vested share based compensation arrangements granted.  That cost is expected to be recognized over a weighted-average period of 21 months.
 
 
NOTE 14 - 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, 2009, 2008, and 2007 were $39,768, $61,787 and $53,761, respectively.

NOTE 15 - 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 2009, 2008 or 2007.

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 16 - CONCENTRATIONS OF CREDIT RISK
 
The Company bids its gas sales on a month to month basis and generally sells to a single customer without commitment to future gas sales to any particular customer. The Company normally sells approximately 93% of its monthly natural gas production to one customer on a month to month basis.  Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse affect on our overall sales operations.

The Company maintains cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 for our interest bearing account in the year ended December 31, 2008.  At December 31, 2008, the Company’s non-interest bearing accounts were fully insured by the FDIC. However, for the year ended December 31, 2009 all account types were insured up to $250,000 per institution.   At December 31, 2009 and 2008, cash in banks exceeded the FDIC limits by approximately $3.3 million and $247,000, respectively. The Company has not experienced any losses on deposits.
 
F-28
 

 

NOTE 17:  QUARTERLY FINANCIAL INFORMATION (UNAUDITED):
 
 
 
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
 
Total Year
2009
         
Revenues
$2,268,170
$1,300,395
$1,211,718
$3,845,302
$8,625,585
Operating income (loss)
(1,441,102)
(460,701)
(1,320,028)
74,962
(3,146,869)
Net income (loss)
$(891,056)
$(294,731)
$(828,825)
$(182,531)
$(2,197,143)
Earnings (loss) per share
         
Diluted
$(0.10)
$(0.03)
$(0.10)
$(0.02)
$(0.24)
Basic
$(0.10)
$(0.03)
$(0.10)
$(0.02)
$(0.24)
           
2008
         
Revenues
$2,990,257
$ 4,710,567
$4,958,322
$6,514,968
$19,174,114
Operating income (loss)
(1,321,506)
1,219,065
2,128,256
(16,388,700)
(14,362,885)
Net income (loss)
$(927,460)
$760,230
$1,373,491
$(9,983,875)
$(8,777,614)
Earnings (loss) per share
         
Diluted
$ (0.12)
$0.09
$0.16
$(1.21)
$(1.06)
Basic
$ (0.12)
$0.09
$0.16
$(1.21)
$(1.06)



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

NOTE 18:  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. This lawsuit arose from a dispute over jointly operated property in which Royale is the 75% owner and operator and NFC is a non-operator with a 25% ownership.  NFC disagrees with the Company’s operations and seeks to remove the Company as operator.  As of the date of this filing, both parties have signed a settlement agreement.  However, until the court enters an order dismissing the case, the case remains an active matter.   


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:

 
·
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.

F-29
 

 
 
·
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 ResourcesThe definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.
 
We have 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 $11.3 million at December 31, 2009, based on natural gas prices ranging from $2.92 per MCF to $3.87 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.

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, 2009, 2008 and 2007 and changes in such quantities during each of the years then ended, were as follows:

F-30
 
 

 


 
2009
 
2008
 
2007
                       
 
Oil (BBL)
 
Gas (MCF)
 
Oil (BBL)
 
Gas (MCF)
 
Oil (BBL)
 
Gas (MCF)
Proved developed and undeveloped reserves:
                     
Beginning of period
24,635
 
3,376,568
 
23,866
 
3,771,967
 
37,000
 
8,160,000
Revisions of previous estimates
 
(437)
 
 
(409,158)
 
 
11,858
 
 
104,796
 
 
954
 
 
(4,048,438)
Production
(8,364)
 
(575,995)
 
(11,089)
 
(714,230)
 
(14,088)
 
(791,195)
Extensions, discoveries and improved recovery
 
-
 
 
2,226,380
 
 
-
 
 
214,035
 
 
-
 
 
784,391
Purchase of minerals in place
       
-
 
-
 
-
 
-
Sales of minerals in place
       
-
 
-
 
-
 
(332,791)
                       
Proved reserves end of period
15,834
 
4,617,794
 
24,635
 
3,376,568
 
23,866
 
3,771,967
                       

 
2009
 
2008
 
2007
                       
 
Oil (BBL)
 
Gas (MCF)
 
Oil (BBL)
 
Gas (MCF)
 
Oil (BBL)
 
Gas (MCF)
                       
Proved developed reserves:
                     
                       
Beginning of period
24,635
 
3,184,966
 
23,866
 
3,413,578
 
37,000
 
4,129,000
                       
End of period
15,834
 
4,562,598
 
24,635
 
3,184,966
 
23,866
 
3,413,578
                       

 
2009
 
2008
 
2007
                       
 
Oil (BBL)
 
Gas (MCF)
 
Oil (BBL)
 
Gas (MCF)
 
Oil (BBL)
 
Gas (MCF)
                       
Proved undeveloped reserves:
                     
                       
Beginning of period
      -
 
   191,602
 
      -
 
   358,389
 
      -
 
4,031,000
                       
End of period
     -
 
     55,196
 
      -
 
   191,602
 
      -
 
   358,389
                       

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, 2009.

The future net cash inflows are developed as follows:

Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.
The estimated future production of proved reserves is priced on the basis of year-end prices.
The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows:

F-31
 
 

 


2010
$
253,180
2011
 
34,810
2012
 
-
Thereafter
 
84,200
     
Total
$
372,190
     
 
 
The resulting future net revenue streams are reduced to present value amounts by applying a ten percent discount.

Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation.  In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing.  The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.

Changes in standardized measure of discounted future net cash flow from proved reserve quantities
 
This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.

   
2009
 
2008
 
2007
             
Future cash inflows
$
17,684,460
$
18,596,000
$
28,421,000
Future production costs
 
(6,013,780)
 
(6,411,000)
 
(7,474,000)
Future development costs
 
(372,190)
 
(744,000)
 
(1,085,000)
Future income tax expense
 
(3,389,547)
 
(3,432,285)
 
(5,958,270)
             
Future net cash flows
 
7,908,943
 
8,008,715
 
13,903,730
             
10% annual discount for estimated timing of cash flows
 
 
(1,647,010)
 
 
(2,042,551)
 
 
(3,258,848)
             
Standardized measure of discounted future net cash flows
 
$
 
6,261,933
 
$
 
5,966,164
 
$
 
10,644,882
             
Sales of oil and gas produced, net of production costs
 
$
 
(957,988)
 
$
 
 (2,097,225)
 
$
 
(3,858,679)
 
           
Revisions of previous quantity estimates
 
(4,006,942)
 
(5,251,154)
 
(8,124,443)
Net changes in prices and production costs
 
815,884
 
(1,809,957)
 
(1,649,513)
Sales of minerals in place
         
(220,631)
Purchases of minerals in place-
           
             
Extensions, discoveries and improved recovery
 
 
3,806,933
 
 
775,819
 
 
3,741,753
Accretion of discount
 
764,641
 
1,698,634
 
1,537,700
             
Net change in income tax
 
(126,759)
 
2,005,165
 
2,572,144
 
           
Net increase (decrease)
$
295,769
$
(4,678,718)
$
(6,001,669)
 
           
 
 
F-32
 

 
Future Development Costs
 
In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves.  The following table estimates the costs to develop and produce our proved reserves in the years 2010 through 2012.

Future development cost of:
 
2010
 
2011
 
2012
Proved developed reserves
$
-
$
-
$
-
Proved non-producing reserves
 
 
152,080
 
 
34,810
 
 
-
Proved undeveloped reserves
 
101,100
 
-
 
-
             
Total
$
253,180
$
34,810
$
-
             

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:

2009
$
0
2008
$
392,055
2007
$
2,093,801



F-33