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| ROYL > SEC Filings for ROYL > Form 10-K on 27-Mar-2009 | All Recent SEC Filings |
27-Mar-2009
Annual Report
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.
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 revenue until drilling is complete. Occasionally, drilling is delayed due to the permitting process, or drilling rig availability. At December 31, 2008 and 2007, Royale Energy had deferred drilling revenue of $4,005,800 and $3,947,097, respectively.
The primary business segment is oil and gas production. Northern and central California account for approximately 93% of the company's successful natural 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.
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.
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 Statement of Financial Accounting Standard 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." 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 discounted cash flows utilizing a discount rate appropriate for risks associated with the related properties or based on fair market values. 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 reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Results of Operations for the Twelve Months Ended December 31, 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 $715,436, or 33.8%, to $2,832,413 for the year ended December 31, 2008, from $2,116,977 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
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 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
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.
General and administrative expenses increased by $237,359 or 5%, from $4,712,624 for the year ended December 31, 2007 to $4,949,983 for the year in 2008. This increase was primarily due to a bad debts write-off in 2008 of approximately $567,521, compared to $262,532 in 2007, for receivables from direct working interest investors whose expenses on non-producing wells are contractually not collectable. 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%).
Results of Operations for the Twelve Months Ended December 31, 2007, as Compared to the Twelve Months Ended December 31, 2006
For the year ended December 31, 2007, we had a net loss of $2,779,207 compared to the net loss of $2,649,701 achieved during 2006. A major component of the loss was an impairment of $2,106,670 due to a decrease in reserve values at year end 2007. The loss also resulted from decreases in revenues from both the turnkey drilling and the oil and natural gas production segments of our business.
Total revenues from operations for the year in 2007 were $16,557,399, a decrease of $8,338,644, or 33.5%, from the total revenues of $24,896,043 in 2006. In 2007 our natural gas revenues decreased due to lower natural gas and oil production and our turnkey drilling revenues declined due to a decrease in the number of wells drilled. Lower oil and natural gas production accounted for 22% of the decrease, and lower turnkey drilling revenues accounted for 76% of the decrease.
Oil and gas lease operating expenses increased by $148,708, or 7.6%, to $2,116,977 for the year ended December 31, 2007, from $1,968,269 for the year in 2006. This increase was mainly due to higher workover costs during the period in 2007 when compared to 2006, as we attempted to increase production on some of our existing wells. When measuring lease operating costs on a production or lifting cost basis, in 2007, the $2,116,977 equates to a $2.27 per mcfe lifting cost versus a $1.53 per mcfe lifting cost in 2006, a 48.4% increase.
For the year ended December 31, 2007, turnkey drilling revenues decreased $6,303,447 to $9,408,103 in 2007 from $15,711,550 in 2006, or 40.1%. We also had a $4,650,583 or 48.3% decrease in turnkey drilling and development costs to $4,977,811 in 2007 from $9,628,394 in 2006. These decreases were mainly due to fewer wells drilled, seven during the year in 2007 while sixteen wells were drilled during the year in 2006, as we focused our efforts into developing the Utah property. We drilled four exploratory wells and three developmental wells in 2007 versus six exploratory wells and ten developmental wells in 2006. Exploratory wells tend to be more expensive due to new lease, geological and geophysical and facility costs. 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 was 47.1% and 38.7% for the years ended December 31, 2007 and 2006, 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 $2,106,670 and $6,191,417 were recorded in 2007 and 2006, respectively. In 2007 and 2006, we recorded impairments in fields where year end reserve values no longer supported the net book values of wells in those fields. 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 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. In 2006, the primary focus of this impairment, $4,068,843, was recorded for our wells in the Texas and Gulf
We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges where doubtful. The Company does not attempt collection 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 2007 and 2006, we established an allowance of $546,874 and $567,000, respectively, for receivables from these Direct Working Interest owners.
The aggregate of supervisory fees and other income was $1,039,204 for the year ended December 31, 2007, a decrease of $179,656 (14.7%) from $1,218,860 during the year in 2006. This decrease was the result of several factors including the decrease in the number of wells operated due to the sale of properties in 2006, the decrease in drilling and 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 $83,718 or 17.3%, to $400,897 in 2007 from $484,615 in 2006.
Depreciation, depletion and amortization expense decreased to $3,585,682 from $5,833,904 a decrease of $2,248,222 (38.5%) for the year ended December 31, 2007, as compared to 2006. 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 assets from our 2006 asset sale and impairments.
We also reevaluated our inventory of capitalized geological lease and land costs, in order to write off those prospects that may be no longer viable. As a result, $423,459 of previously capitalized costs were written off and recorded as geological and geophysical expense during 2007, compared with $400,306 written off in 2006, a $23,153 or 5.8% increase. This expense is directly attributable to the selection and prioritization of the quality of the company's drilling prospects.
General and administrative expenses decreased by $416,450 or 8.1%, from $5,129,074 for the year ended December 31, 2006 to $4,712,624 for the year in 2007. This decrease was primarily due to a bad debts write-off in 2006 of approximately $582,204, compared to $262,532 in 2007, for receivables from direct working interest investors whose expenses on non-producing wells are contractually not collectable. Legal and accounting expense increased to $928,628 for the year, compared to $397,575 for year 2006, a $531,053 or 133.6% increase. This increase was due to higher legal fees due to litigation defending property rights during 2007.
During 2007 we sold our interests in two non oil and gas assets resulting in a loss on sale of $135,396. In November 2006 we sold 19 of our producing Sacramento Basin wells and support facilities for $4,510,000, resulting in a gain on sale of $3,263,368.
During 2007 interest expense decreased to $152,547 from $523,139 in 2006, a $370,592 or 70.8% decrease. This decrease was due to principal balance reduction on our line of credit and to the decrease in the interest rate charged to the company, which went from 8.75% at December 31, 2006, to 7.75% at December 31, 2007.
In 2007 we had an income tax benefit of $1,258,484 mainly due to our net loss before taxes of $4,037,691. In 2006 we also had an income tax benefit of $1,062,054 also due to our net loss before taxes of $3,711,755 and the utilization of our depletion carryforwards. 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, 2008, Royale Energy had current assets totaling $8,891,126 and current liabilities totaling $14,325,985, a $5,434,859 working capital deficit. We had cash and cash equivalents at December 31, 2008 of $1,330,739 compared to $3,848,968 at December 31, 2007.
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.
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