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ROYL > SEC Filings for ROYL > Form 10-K/A on 30-Apr-2013All Recent SEC Filings

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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 eighteen years, Royale Energy has primarily acquired and developed producing and non-producing natural gas properties in California. In 2004, Royale Energy began developing leases in Utah. The most significant factors affecting the results of operations are (i) changes in oil and natural gas production levels and reserves, (ii) recording of turnkey drilling revenues and the associated drilling expense, and (iii) the change in commodities price of natural gas and oil reserves owned by Royale Energy.

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Critical Accounting Policies

Revenue Recognition

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

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

Royale Energy derives DWI revenue from sales of working interests in wells to be drilled to high net worth individuals. DWI investments relating to pre-drilling costs are non-refundable. The company holds all funds invested as deferred turnkey drilling until drilling is complete. Occasionally, drilling is delayed due to the permitting process or drilling rig availability. At December 31, 2012 and 2011, Royale Energy had deferred turnkey drilling of $8,693,743 and $6,909,666 respectively.

The primary business segment is oil and gas production. Northern and central California accounted for approximately 99% of the Company's successful natural gas production in 2012. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines. Monthly, price data and daily production are used to invoice customers for amounts due to Royale Energy and other working interest owners. Royale Energy operates virtually all of its own wells and receives industry standard operator fees.

Upon the sale or retirement of a complete field of a proved property, the Company eliminates the cost from its books, and the resultant gain or loss is recorded to Royale Energy's Statement of Operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale Energy's Statement of Operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

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.


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.

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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 are charged to expense. We periodically review for impairment of proved properties on a field-by-field basis. Unamortized capital costs are measured on a field basis and are reduced to fair value if it is determined that the sum of expected future net cash flows are less than the net book value. We determine if impairment has occurred through either adverse changes or as a result of its periodic review for impairment. Impairment is measured on a 10% discounted cash flows basis. We regard impairment costs of undeveloped properties as a component of our turnkey drilling overhead, since impairment costs amount to a write-down of previously acquired property inventory that we were unable to successfully develop as part of our turnkey drilling program.


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. 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 tas assets is needed. Information about the company's financial position and its results of operations for the current and preceding years will be used.

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

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

Results of Operations for the Twelve Months Ended December 31, 2012, as Compared to the Restated Twelve Months Ended December 31, 2011

For the year ended December 31, 2012, we recorded a net loss before taxes of $4,526,117 a $1,394,630 improvement when compared to a net loss before taxes of $5,920,747 during 2011. Total revenues from operations in 2012 were $4,394,745, a decrease of $7,137,665, or 61.9%, from the total revenues of $11,532,410 in 2011, the result of both lower turnkey drilling revenues and oil and natural gas sales. Total expenses from operations in 2012 were $8,741,001, a decrease of $9,333,701, or 51.6%, from the total expenses of $18,074,702 in 2011, due mainly to decreases in both drilling and impairment costs in 2012. At year end 2012, management reviewed the realizability of the Company's net deferred tax assets and concluded that certain conditions were met, as outlined above in the Certain Accounting Policy's Deferred Income Tax section and in FASB ASC 740-10, under which it was appropriate for Royale to record a valuation allowance against the net deferred tax assets of $10,176,227, resulting in a net loss of $11,961,026 in 2012 compared to a net loss of $4,188,241 in 2011.

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In 2012, revenues from oil and gas production decreased by 65.7% to $1,673,538 from $4,879,397 in 2011, due to lower oil and natural gas production. This decrease in production was due to the natural declines of our existing wells and lower commodity prices received in 2012. The net sales volume of natural gas for the year ended December 31, 2012, was approximately 559,590 MCF with an average price of $2.74 per MCF, versus 1,144,469 MCF with an average price of $4.08 per MCF for 2011. This represents a decrease in net sales volume of 584,879 MCF or 51.1%. The net sales volume for oil and condensate (natural gas liquids) production was approximately 1,558 barrels with an average price of $90.75 per barrel for the year ended December 31, 2012, compared to 2,264 barrels at an average price of $90.48 per barrel for the year in 2011. This represents a decrease in net sales volume of 706 barrels, or 31.2%. This decrease was mainly due to the sale of several oil producing wells in the first quarter of 2011.

Oil and gas lease operating expenses decreased by $378,170, or 24.9%, to $1,139,750 for the year ended December 31, 2012, from $1,517,920 for the year in 2011. This decrease was mainly due to lower transportation costs due to the decrease in production volumes and lower plugging costs during 2012. When measuring lease operating costs on a production or lifting cost basis, in 2012, the $1,139,750 equates to a $2.00 per MCFE lifting cost versus a $1.31 per MCFE lifting cost in 2011, a 52.7% increase, due to the lower production volumes in 2012.

For the year ended December 31, 2012, turnkey drilling revenues decreased $3,765,564 to $2,028,863 from $5,794,427 in 2011, or 65.0%. We also had a $3,073,836 or 87.2% decrease in turnkey drilling and development costs to $449,536 in 2012 from $3,523,372 in 2011. These decreases in both turnkey revenues and costs were due to the drilling of two wells in 2012, one developmental and one exploratory well versus the drilling of seven wells in 2011, six developmental and one exploratory well. Our gross margins, or profits, on drilling depend on our ability to accurately estimate the costs associated with the development of projects in which we sell working interests and to acquire viable properties that can be successfully developed. Costs associated with contract drilling depend on location, well depth, weather, and availability of drilling contractors and equipment. Our gross margin on drilling increased to 77.8% from 39.2% for the years ended December 31, 2012 and 2011, respectively. Gross margin is calculated as the difference between turnkey drilling revenue and turnkey drilling expense. However, management believes that a portion of its impairment losses should also be considered as a cost of drilling in determining the profitability of this segment, because impairment costs are incurred in the selection of higher quality prospects for ultimate development.

Impairment losses of $200,778 and $4,529,058 were recorded in 2012 and 2011, respectively. In both years, we recorded impairments in wells or fields where year-end reserve values were less than the net book values of wells or where lease and land costs were no longer viable. In 2012, one Utah well and two California wells were impaired by $ 11,276 and $60,,789 respectively. Also in 2012, we recorded lease impairments of $119,322 on various capitalized lease and land costs that were no longer viable. In 2011, two California fields, the Lonestar and Bowerbank fields were impaired $3,776,385 and $28,566, respectively, while our Utah field was also impaired by $710,124. These impairments were due to lower proved developed reserves than current book values primarily due to a substantial drop in the price of natural gas. Additionally in 2011, we recorded lease impairments of $12,959 on various capitalized lease and land costs that were no longer viable.

Bad debt expense for 2012 and 2011 were $263,767 and $86,294, respectively. These expenses arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment. We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges where doubtful. By contract, the Company may not collect some charges from its Direct Working Interest owners for certain wells that ceased production or had been sold during the year, to the extent that these charges exceed production revenue

The aggregate of supervisory fees and other income was $692,344 for the year ended December 31, 2012, a decrease of $166,242 (19.4%) from $858,586 during the year in 2011. This decrease was mainly due to lower pipeline and compressor revenues generated from the decrease in natural gas production. Supervisory fees are charged in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for reimbursement of expenses associated with the joint accounting for billing, revenue disbursement, and payment of taxes and royalties. These charges are reevaluated each year and adjusted up or down as deemed appropriate by a published report to the industry by Ernst & Young, LLP, Certified Public Accountants. Supervisory fees increased $69,821 or 18.1%, to $455,396 in 2012 from $385,575 in 2011.

Depreciation, depletion and amortization expense decreased to $1,448,002 from $2,362,065 a decrease of $914,063 (38.7%) for the year ended December 31, 2012, as compared to 2011. The depletion rate is calculated using production as a percentage of reserves. This increase in depletion expense was due to the lower natural gas production during 2012 and a lower oil and gas asset base due to our 2011 impairments, resulting in a decreased depletion of our oil and natural gas properties.

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General and administrative expenses decreased by $398,873 or 9.9%, from $4,039,209 for the year ended December 31, 2011, to $3,640,336 for the year in 2012. This decrease was primarily due to lower employee related costs. Legal and accounting expense decreased to $518,511 for the year, compared to $933,856 for 2011, a $415,345 or 44.5% decrease. This decrease was the result of lower legal fees in 2012 primarily related to the conclusion of the Mountain West and National Fuel litigation in 2011.

Marketing expense for the year ended December 31, 2012, decreased $119,377 or 16.7%, to $594,118, compared to $713,495 for the year in 2011. Marketing expense usually varies from period to period according to the number of marketing events attended by personnel and their associated costs. During 2012, in an effort to control costs, we attended fewer marketing conferences and attempted to negotiate lower conference fees.

During the years in 2012 and 2011, we incurred $423,459 and $111,390, respectively, in geological and geophysical costs in order to increase our oil and natural gas prospect base. These costs were incurred at the same seismic survey in Northern California. Additionally during 2012, we had a write down of $62,744 on certain oil and gas inventory to its estimated current market value. In 2011, we also had a write down of $258,043 on certain oil and gas pipeline inventory to its estimated current market value. In 2011, we sold our working interest in two separate non-core properties and other equipment resulting in a gain of $759,763. The properties were located in Kern County, California and Gaines County, Texas.

During 2012, interest expense increased to $195,009 from $138,218 in 2011, a $56,791 or 41.1% increase. This increase was mainly due to the interest on a new convertible note payable obtained during the fourth quarter of 2012. Further details concerning Royale's notes payable and line of credit usage can be found in the Capital Resources and Liquidity section below.

In 2012, we had income tax expense of $ 7,434,909 due to the valuation allowance recognized against our net deferred tax assets. In 2011, we had an income tax benefit of $ 1,732,506 due to our net loss before taxes of $ 5,920,747. For 2012, the use of a percentage depletion carryover valuation allowance created from the current and past operations results in an effective tax rate less than the normal federal rate of 34% plus the relevant state rates (mostly California, 9.3%).

Capital Resources and Liquidity

At December 31, 2012, Royale Energy had current assets totaling $6,540,592 and current liabilities totaling $ 15,886,654, a $6,978,713 working capital deficit. We had cash and cash equivalents at December 31, 2012 of $1,489,930 compared to $2,946,131 at December 31, 2011.

Our capital expenditure commitments occur as we decide to drill wells to develop our prospects. We generally do not decide to drill any prospect until we have sold a portion of the working interest in a prospect to third parties to diversify our risk and receive a portion of the funds to drill each prospect. We place funds that we receive from third party investors into a separate cash account until they are required for expenditures on each well.

The Company has traditionally relied on available credit and cash flows from operation for capital expenditures for oil and gas drilling and development, in addition to the cash generated from selling a portion of the working interest in prospects to third parties. As discussed in Results of Operations, page 14, the Company's revenues both from oil and gas sales and from sales of working interests declined in 2012. As a result of the decline in natural gas prices, we curtailed our drilling efforts in 2012, drilling only two wells in 2012, compared to seven wells in 2011. The decline in revenue also led the Company to seek alternative financing sources for its drilling activities.

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

In October 2012, the Company obtained $3 million from sale of a convertible note. See, The Company's Prospectus Supplement filed pursuant to Rule 424(b) on October 29, 2012, and the Company's Form 8-K filed on October 29, 2012. The Company used these proceeds for general corporate purposes, including the reduction of outstanding bank debt and for capital expenditures on oil and gas development. The note may, at the Company's option, be repaid by converting the interest and principal amounts due to common stock, thus reducing the Company's cash needs to service its debt.

In February 2012, the Company entered into a sales agreement with C. K. Cooper & Company, Inc., to sell up to $10 million of common stock in an "at the market" offering as defined in Rule 415. In 2012, the Company sold approximately $4.6 million of common stock pursuant to the sales agreement. The Company expects to sell additional common stock pursuant to the sales agreement in 2013.

Beginning in January 2012, the Company began extensive cost cutting measures in General and Administrative, Legal and Accounting, and Marketing expense. These measures enabled us to reduce our operating expenses by approximately $1 million for 2012, compared to 2011, and expect that these measures will carry forward into 2013.

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

At the end of 2012, our accounts receivable totaled $3,969,160 compared to $1,872,067 at December 31, 2011, a $2,097,093 or 112.02% increase. This was primarily due to an approximately $2,500,000 receivable, as part of the sale of common stock discussed above, due at December 31, 2012. This common stock receivable was collected on January 4, 2013. At December 31, 2012, our accounts payable and accrued expenses totaled $4,932,469, an increase of $389,728 or 8.6% over the accounts payable at the end of 2011 of $4,542,741. This increase was mainly due to increased drilling activity at year end 2012 when compared to year end 2011.

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

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

The following schedule summarizes our known contractual cash obligations at December 31, 2012, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.

                            Obligations         2013           2014-2015         2016          Beyond

Office lease               $   1,066,614     $   403,873     $   662,741     $        -     $          -
Revolving Line of Credit         350,000         350,000               -              -                -
Convertible Note               3,333,333       3,333,333
Total                      $   4,749,947     $ 4,087,206     $   662,741     $        -     $          -

Operating Activities. For the years ended December 31, 2012 and 2011, cash provided by operating activities totaled $226,193 and $1,578,482, respectively. This difference in cash was from our lower oil and natural gas sales due to lower production volumes and price received during the year in 2012.

Investing Activities. For the year ended December 31, 2012, cash used by investing activities was $4,486,093 compared to $3,948,464 used by investing activities in 2011, an increase of $537,629 or 13.6%. This increase in cash used was mainly due to finalizing and funding our agreement with the State of Alaska to obtain approximately 90,000 lease acres, in addition to the drilling two wells during 2012. In 2011, we drilled or participated in the drilling of seven wells and received proceeds of $806,353 relating to the sale of certain oil and gas properties in Kern County, California and Gaines County, Texas. As part of the sale, we retained an overriding royalty interest in the acreage.

Financing Activities. Net cash provided by financing activities totaled $2,803,699 and $601,488 for the years ended December 31, 2012 and 2011, respectively. The increase in cash provided was due to the obtaining of a new note payable and the sales of common stock during the year in 2012. In 2012, options were exercised by one director for a total of 88,692 shares of the Company's common stock in exchange for proceeds of $299,500. Additionally during the year, Royale received proceeds, net of fees, of $2,119,510 and issued 528,996 shares of its common stock relating to its market equity offering program. As discussed above, the Company received approximately $2.8 million from a convertible note payable during the year in 2012. These proceeds were added to working capital and used for ordinary operating expense. Also during the period in 2012, five directors exchanged 195,000 options in a cashless exercise for 76,346 common shares. In 2011 several warrants were exchanged for shares of Royale's common stock. Royale received $1,051,488 and issued 468,928 shares of its common stock relating to these exercises. Additionally during the period in 2011, we issued 18,440 shares of common stock to a member of the board of directors in a cashless stock options exercise.

Changes in Reserve Estimates

During 2012, our overall proved developed and undeveloped reserves decreased by 1.6% and our previously estimated proved developed and undeveloped reserve quantities were revised downward by approximately 0.4 million cubic feet of natural gas. This downward revision was primarily due to two California wells, drilled in 2011, which had lower than previously estimated proved producing and non-producing natural gas reserves. See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-30.

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During 2011, our overall proved developed and undeveloped reserves decreased by 25.5% and our previously estimated proved developed and undeveloped reserve quantities were revised downward by approximately 1 million cubic feet of natural gas. This downward revision was primarily due four California wells in our Lonestar field, one of which was drilled in 2009 and the other three drilled in 2010, which had lower than previously estimated proved producing and non-producing gas reserves.

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