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ROYL > SEC Filings for ROYL > Form 10-K on 11-Mar-2014All Recent SEC Filings

Show all filings for ROYALE ENERGY INC



Annual Report

Item 6 Management's Discussion and Analysis of Financial Condition
and Results of Operations

The following discussion should be read in conjunction with Royale Energy's Financial Statements and Notes thereto and other financial information relating to Royale Energy included elsewhere in this document.

For the past twenty-one 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) turnkey drilling activities, and (iii) the change in commodities price of natural gas and oil reserves owned by Royale Energy.

Critical Accounting Policies

Revenue Recognition

Royale's primary business is oil and gas production. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines. Monthly, price data and daily production are used to invoice customers for amounts due to Royale Energy and other working interest owners. Royale Energy operates virtually all of its own wells and receives industry standard operator fees.

Royale Energy generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.

Revenues from the production of oil and natural gas properties in which the Royale Energy has an interest with other producers are recognized on the basis of Royale Energy's net working interest. Differences between actual production and net working interest volumes are not significant.

Royale Energy's financial statements include its pro rata ownership of wells. Royale Energy usually sells a portion of the working interest in each well it drills or participates in to third party investors and retains a portion of the prospect for its own account. Royale Energy generally retains about a 50% working interest. All results, successful or not, are included at its pro rata ownership amounts: revenue, expenses, assets, and liabilities as defined in FASB ASC 932-323-25 and 932-360.

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Oil and Gas Property and Equipment

Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.

Royale Energy uses the "successful efforts" method to account for its exploration and production activities. Under this method, Royale Energy accumulates its proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalizes expenditures for productive wells. Royale Energy amortizes the costs of productive wells under the unit-of-production method.

Royale Energy carries, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where Royale Energy is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.

Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods.
Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain Royale Energy's wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

Proved oil and gas properties held and used by Royale Energy are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

Royale Energy estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated evaluation assumptions for crude oil commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on assumptions developed annually for evaluation purposes.

Impairment analyses are generally based on proved reserves. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value. During 2013 and 2012, impairment losses of $70,203 and $145,461, respectively, were recorded on various capitalized lease and land costs that were no longer viable.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale Energy expects to hold the properties. The valuation allowances are reviewed at least annually.

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Upon the sale or retirement of a complete field of a proved property, Royale Energy eliminates the cost from its books, and the resultant gain or loss is recorded to Royale Energy's Statement of Operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale Energy's Statement of Operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should Royale Energy's turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the "successful efforts" method.

Royale Energy sponsors turnkey drilling agreement arrangements in unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account; and are recognized only upon making this determination after Royale's obligations have been fulfilled.

The contracts require the participants pay Royale Energy the full contract price upon execution of the agreement. Royale Energy completes the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for its proportionate share of operating costs. Royale Energy retains legal title to the lease. The participants purchase a working interest directly in the well bore.

In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed and the interest is conveyed to the participant.

Since the participant's interest in the prospect is limited to the well, and not the lease, the investor does not have a legal right to participate in additional wells drilled within the same lease. However, it is the Company's policy to offer to participants in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well with similar turnkey drilling agreement terms.

A certain portion of the turnkey drilling participant's funds received are non-refundable. The company holds all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed due to the permitting process or drilling rig availability. At December 31, 2013 and 2012, Royale Energy had Deferred Drilling Obligations of $6,125,933 and $8,693,743 respectively.

If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the contact and return the remaining funds to the participant. Included in cash and cash equivalents are amounts for use in completion of turnkey drilling programs in progress.

Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.


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 prove oil, plant products and gas reserve volumes and the future development costs. Actual results could differ from those estimates.

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Deferred Income Taxes

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. All available evidence, both positive and negative, shall be considered to determine whether, based on the weight of that evidence, a valuation allowance for deferred tax assets is needed. Information about the company's financial position and its results of operations for the current and preceding years will be used.

The company shall use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence shall be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists, the more positive evidence is necessary and the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. A cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome.

Future realization of a tax benefit sometimes will be expected for a portion, but not all of a deferred tax asset, and the dividing line between the two portions may be unclear. In those circumstances, application of judgment based on a careful assessment of all available evidence is required to determine the portion of a deferred tax asset for which it is more likely than not a tax benefit will not be realized.

Results of Operations for the Twelve Months Ended December 31, 2013, as Compared to the Restated Twelve Months Ended December 31, 2012

For the year ended December 31, 2013, we recorded a net income of $1,149,153 a $14,839,769 improvement when compared to a net loss of $13,690,616 during 2012. Total revenues from operations in 2013 were $2,573,061, an increase of $207,179, or 8.8%, from the total revenues of $2,365,882 in 2012, due to higher natural gas prices during 2013. Total expenses from operations in 2013 were $5,948,485, a decrease of $1,503,792, or 20.1%, from the total expenses of $7,452,277 in 2012, due to decreases in most categories due to continued cost control measures. At year end 2012, management reviewed the likelihood of realizing the Company's net deferred tax assets and concluded that certain conditions were met, as outlined above in the Certain Accounting Policy's Deferred Income Tax section and in FASB ASC 740-10, under which it was appropriate for Royale to record a valuation allowance against the net deferred tax assets resulting in a tax adjustment of $9,187,821. The higher net profits in 2013 were also the result of gains from our turnkey drilling programs and the sale of a portion of our oil and gas leases in Alaska.

In 2013, revenues from oil and gas production increased by 14.3% to $1,913,364 from $1,673,538 in 2012. This increase was due to higher natural gas commodity prices received during 2013. The net sales volume of natural gas for the year ended December 31, 2013, was approximately 498,778 MCF with an average price of $3.64 per MCF, versus 559,590 MCF with an average price of $2.74 per MCF for 2012. This represents a decrease in net sales volume of 60,812 MCF or 10.9%. This decrease in production volume was due to the natural declines of our existing wells. The net sales volume for oil and condensate (natural gas liquids) production was approximately 1,019 barrels with an average price of $93.79 per barrel for the year ended December 31, 2013, compared to 1,558 barrels at an average price of $90.75 per barrel for the year in 2012. This represents a decrease in net sales volume of 539 barrels, or 34.6%. This decrease was also due to the natural declines on existing wells. Northern and central California accounted for approximately 99% of the Company's successful natural gas production in 2013.

Oil and natural gas lease operating expenses decreased by $154,317, or 14.2%, to $936,631 for the year ended December 31, 2013, from $1,090,948 for the year in 2012. This decrease was mainly due to lower tax expenses from lower production and sales volumes in previous years. When measuring lease operating costs on a production or lifting cost basis, in 2013, the $936,631 equates to a $ 1.86 per MCFE lifting cost versus a $ 1.92 per MCFE lifting cost in 2012, a 3% decrease, due to cost cutting efforts in 2013. Delay rental costs increased by $408,752 or 838%, to $457,554 for the year in 2013 from $48,802 in 2012. This increase was due to higher delay rentals for our Alaska leases.

At December 31, 2013, Royale Energy had a Deferred Drilling Obligation of $6,125,933. During 2013, we disposed of $8,028,190 of these obligations upon completing the drilling of six wells, five exploratory and one developmental, in addition in participating in the drilling of two additional wells with an industry partner, resulting in a gain of $2,008,734. In 2012, we disposed of $1,468,384 upon completing our obligation by drilling two wells, one exploratory and one developmental, resulting in a gain of $763,461. Royale expects to dispose of approximately $2.8 million in the first six months of 2014 with the remaining $3.3 million disposed of by the end of 2014.

During 2013 we recorded a gain of $2,684,801 from the sale of a portion of our western block oil and gas leases in Alaska. See our Current Report Form 8-K filed on May 24, 2013. In 2013, we also recorded a gain of $173,013 on the sale of certain California natural gas leases. During the year in 2013, we recorded a gain of $40,000 on the sale of oil and gas leases in Texas and recorded a loss of $82,184 on the sale of surface casing previously included in inventory. During the year in 2012, we recorded a gain of $7,048 on the sale of a non-company owned stock and recorded a write down of $62,744 on certain oil and gas inventory to its estimated current market value.

Impairment losses of $70,203 and $145,461 were recorded in 2013 and 2012, respectively. In both years, we recorded impairments on various capitalized lease and land costs that were no longer viable.

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Bad debt expense for 2013 and 2012 were $146,704 and $263,767, respectively. The expenses in 2013 and 2012 arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment. We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges where doubtful. By contract, the Company may not collect some charges from its Direct Working Interest owners for certain wells that ceased production or had been sold during the year, to the extent that these charges exceed production revenue

The aggregate of supervisory fees and other income was $659,697 for the year ended December 31, 2013, a decrease of $32,647 (4.7%) from $692,344 during the year in 2012. This decrease was mainly due to lower overhead rates during the period in 2013 due to lower production volumes. Supervisory fees are charged in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for reimbursement of expenses associated with the joint accounting for billing, revenue disbursement, and payment of taxes and royalties. These charges are reevaluated each year and adjusted up or down as deemed appropriate by a published report to the industry by Ernst & Young, LLP, Certified Public Accountants. Supervisory fees decreased $40,546 or 8.9%, to $414,850 in 2013 from $455,396 in 2012.

Depreciation, depletion and amortization expense decreased to $309,806 from $664,131 a decrease of $354,325 (53.4%) for the year ended December 31, 2013, as compared to 2012. The depletion rate is calculated using production as a percentage of reserves. This decreased expense in 2013 was mainly due to a lower depreciation rate because of changes to our cost recovery method. See Note 16 to our Financial Statements for the Years Ended December 31, 2013 and 2012 - Restatement to Reflect Change in Revenue Recognition Policy.

General and administrative expenses decreased by $360,831 or 9.9%, from $3,640,336 for the year ended December 31, 2012, to $3,279,505 for the year in 2013. This decrease was primarily due to lower employee related compensation expenses during the period in 2013, resulting from continued cost control measures. Legal and accounting expense decreased to $326,270 for the year, compared to $518,511 for 2012, a $192,241 or 37.1% decrease. This decrease was the result of lower legal fees in 2013 primarily related to a litigation settlement reached in 2012.

Marketing expense for the year ended December 31, 2013, decreased $261,636 or 44%, to $332,482, compared to $594,118 for the year in 2012. Marketing expense usually varies from period to period according to the number of marketing events attended by personnel and their associated costs. During 2013, in an effort to control costs, we attended fewer marketing conferences and attempted to negotiate lower conference fees.

During the years in 2013 and 2012, we incurred $50,145 and $423,459, respectively, in geological and geophysical costs in order to increase our oil and natural gas prospect base. During 2011, we began a seismic survey in Northern California of which a majority of the actual seismic work took place during the first quarter of 2012.

During 2013, interest expense increased to $304,472 from $195,009 in 2012, a $109,463 or 56.1% increase. This increase was mainly due to the interest on a convertible note payable obtained during the fourth quarter of 2012. Further details concerning Royale's notes payable and line of credit usage can be found in the Capital Resources and Liquidity section below.

In 2013, we did not have an income tax expense due to the use of a percentage depletion carryover valuation allowance created from the current and past operations resulting in an effective tax rate less than the normal federal rate of 34% plus the relevant state rates (mostly California, 9.3%). In 2012, we had income tax expense of $9,187,821 due mainly to the valuation allowance recognized against our net deferred tax assets.

Capital Resources and Liquidity

At December 31, 2013, Royale Energy had current assets totaling $7,724,068 and current liabilities totaling $11,482,947, a $3,758,879 working capital deficit. We had cash and cash equivalents at December 31, 2013 of $4,878,233 compared to $1,489,930 at December 31, 2012.

Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations. We believe that we have sufficient liquidity for the foreseeable future and do not foresee any liquidity demands that cannot be met from cash flow or financing activities, including ongoing operations as the Company continues to increase its well inventory or additional sales of equity or debt securities pursuant to a Registration Statement on Form S-3 filed with the SEC.

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At the end of 2013, our accounts receivable totaled $ 1,680,792 compared to $3,969,160 at December 31, 2012, a $2,288,368 or 57.7% decrease. This was primarily due to an approximately $2,500,000 receivable, as part of the sale of common stock due at December 31, 2012. This common stock receivable was collected on January 4, 2013. At December 31, 2013, our accounts payable and accrued expenses totaled $5,332,323, an increase of $399,855 or 8.1% over the accounts payable at the end of 2012 of $4,932,468. This increase was mainly due to increased drilling activity at year end 2013 when compared to year end 2012.

In October 2012, the Company obtained $3 million from the issuance of a convertible note. See the Company's Prospectus Supplement filed pursuant to Rule 424(b) on October 29, 2012, and the Company's Form 8-K filed on October 29, 2012. The Company used these proceeds for general corporate purposes, including the reduction of outstanding bank debt and for capital expenditures on oil and gas developments. The note may, at the Company's option, be repaid by converting the interest and principal amounts due to common stock, thus reducing the Company's cash needs to service its debt. In January 2013, the scheduled payment of $854,167 was paid in cash, which included $833,333 in principal and $20,834 in interest. In April 2013, 479,589 common shares were issued in lieu of the scheduled payment of $833,333. According to the note agreement, the note holders may elect to convert the principal balance into shares of the Company's common stock. During 2013, the note holders submitted conversion notices to the Company such that 787,055 common shares were issued for a reduction in the note principal of $1,666,666. In September 2013, this note was paid in full. In addition to the note, Royale issued a warrant for 500,000 shares of its common stock. The fair market value of this warrant was offset against the value of the warrant and amortized over the life of the loan. During the life of the loan, $100,779 was expensed to interest expense in 2012 in excess 301,415 in 2013 with the remaining 1,144,084 recorded to additional paid in capital in 2013.

In February 2009, we entered into an agreement with Texas Capital Bank, N.A. for a new revolving line of credit and letter of credit facility, also secured by our oil and gas properties, of up to $14,250,000 and separate letter of credit facility of up to $750,000, for the purposes of refinancing Royale's existing debt and to fund development, exploration and acquisition activities as well as other general corporate purposes. The scheduled maturity date for the loan was February 13, 2013. At December 31, 2012, we had a current borrowing base and outstanding indebtedness on this loan of $350,000. During January 2013, the balance of $350,000 on this credit facility was paid in full. In February 2013, the revolving credit agreement matured.

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

The following schedule summarizes our known contractual cash obligations at December 31, 2013, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.

                            Obligations         2014           2015-2016         2017         Beyond

Office lease               $     662,742     $   415,842     $   246,900     $        -     $         -
Building Purchase Note     $  2,283,919          104,776         228,602        114,301       1,836,240
Total                      $   2,946,661     $   520,618     $   475,502     $  114,301     $ 1,836,240

Operating Activities. For the years ended December 31, 2013 and 2012, cash used by operating activities totaled $2,911,000 and $1,353,134, respectively. This $1,557,866 increase in cash used was mainly due to the gain on sale of a portion of its Alaska leases of approximately $2.8 million and the decrease of our deferred drilling obligations through increased drilling during the period in 2013.

Investing Activities. For the year ended December 31, 2013, cash provided by investing activities was $5,233,341 compared to $2,906,766 used by investing activities in 2012, a difference of $8,134,107. This difference was primarily due to the sale of a portion of our leases in Alaska, from which we received proceeds of approximately $4 million, during the period in 2013. During 2013, we also drilled 6 wells resulting in expenditures of approximately $7 million and proceeds of approximately $8 million from our Turnkey drilling programs. In 2012 we drilled two wells and finalized our purchase of the Alaska leases resulting in expenditures of $4.4 million and proceeds from our drilling program of approximately $1.5 million.

Financing Activities. Net cash provided by financing activities totaled $1,065,962 and $2,803,699 for the years ended December 31, 2013 and 2012, respectively. This difference in cash was mainly due to the proceeds received during 2013 for common stock sales and warrant exercises. During 2013 Royale . . .

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