Royale Energy Inc. (ROYL, Financial) filed Annual Report for the period ended 2010-12-31.
Royale Energy Inc. has a market cap of $58 million; its shares were traded at around $5.67 with a P/E ratio of 81 and P/S ratio of 6.8.
In 2010, revenues from oil and gas production increased by 8.8% to $3,047,201 from $2,800,557 in 2009, due to slight increases in both production and the commodity prices received for our oil and natural gas production. The net sales volume of natural gas for the year ended December 31, 2010, was approximately 603,330 MCF with an average price of $4.28 per MCF, versus 575,995 MCF with an average price of $4.09 per MCF for 2009. This represents an increase in net sales volume of 27,335 MCF or 4.7%. This increase was due to higher production volumes of wells drilled and put online during the later part of the year. The net sales volume for oil and condensate (natural gas liquids) production was approximately 6,511 barrels with an average price of $70.95 per barrel for the year ended December 31, 2010, compared to 8,364 barrels at an average price of $52.92 per barrel for the year in 2009. This represents a decrease in net sales volume of 1,853 barrels, or 22.2%.
Oil and gas lease operating expenses decreased by $194,066, or 13.7%, to $1,221,904 for the year ended December 31, 2010, from $1,415,970 for the year in 2009. This decrease was mainly due to continuing cost control measures, lower workover costs and other reduced lease operating costs during 2010. When measuring lease operating costs on a production or lifting cost basis, in 2010, the $1,221,904 equates to a $1.83 per MCFE lifting cost versus a $2.15 per MCFE lifting cost in 2009, a 14.9% decrease.
For the year ended December 31, 2010, turnkey drilling revenues increased $2,806,469 to $7,868,273 from $5,061,804 in 2009, or 55.4%. We also had a $413,164 or 19.2% increase in turnkey drilling and development costs to $2,560,068 in 2010 from $2,146,904 in 2009. In 2010 we drilled nine wells, seven exploratory wells and two developmental wells versus five wells, three exploratory wells and two developmental wells in 2009. Our gross margins, or profits, on drilling depend on our ability to accurately estimate the costs associated with the development of projects in which we sell working interests and to acquire viable properties that can be successfully developed. Costs associated with contract drilling depend on location, well depth, weather, and availability of drilling contractors and equipment. Our gross margin on drilling increased to 67.5% from 57.6% for the years ended December 31, 2010 and 2009, respectively. Gross margin is calculated as the difference between turnkey drilling revenue and turnkey drilling expense. However, management believes that a portion of its impairment losses should
Impairment losses of $500,144 and $1,935,861 were recorded in 2010 and 2009, respectively. In both years, we recorded impairments in fields where year end reserve values were less than the net book values of wells or where lease and land costs that were no longer viable. In 2010, the River Island field was impaired $233,521 due to lower proved producing reserves than current book values. Additionally, two other California fields, Dunnigan Hills, and Rio Vista were impaired $22,118 and $17,931, respectively, also due to lower proved producing reserves than current book values. Our Bowerbank field in California was impaired $24,680 due to lower proved undeveloped reserves than current book values. In 2009, the majority of the impairment, $1,124,293, was recorded in our Utah fields, where various recently drilled wells had significantly lower proved developed nonproducing reserves than originally estimated. Much of these were costs carried over from wells drilled in 2008. Our Elkhorn Slough and East Rice Creek fields, both in California, were impaired $341,098 and $205,173, respectively, due to lower proved producing reserves than their current book values. Two other California fields, the Rio Vista and Bowerbank, were impaired $74,124 and $71,975, respectively, due to lower proved undeveloped reserves than originally estimated. Additionally in 2010 and 2009, we recorded lease impairments of $201,883 and $112,165, respectively, on various capitalized lease and land costs that were no longer viable.
The aggregate of supervisory fees and other income was $682,966 for the year ended December 31, 2010, a decrease of $80,258 (10.5%) from $763,224 during the year in 2009. This decrease was mainly due to the 2009 granting of a seismic license to an industry member for which we were compensated. Supervisory fees are charged in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for reimbursement of expenses associated with the joint accounting for billing, revenue disbursement, and payment of taxes and royalties. These charges are reevaluated each year and adjusted up or down as deemed appropriate by a published report to the industry by Ernst & Young, LLP, Certified Public Accountants. Supervisory fees increased $5,747 or 1.5%, to $394,483 in 2010 from $388,736 in 2009.
Read the The complete Report
Royale Energy Inc. has a market cap of $58 million; its shares were traded at around $5.67 with a P/E ratio of 81 and P/S ratio of 6.8.
Highlight of Business Operations:
For the year ended December 31, 2010, we achieved a net profit of $1,308,028, a $3,505,171 improvement when compared to our net loss of $2,197,143 during 2009. This improvement was primarily due to higher turnkey drilling revenues due to an increase in the number of wells drilled during 2010. Total revenues from operations for the year in 2010 were $11,598,440, an increase of $2,972,855, or 34.5%, from the total revenues of $8,625,585 in 2009, also the result of higher turnkey drilling revenues.In 2010, revenues from oil and gas production increased by 8.8% to $3,047,201 from $2,800,557 in 2009, due to slight increases in both production and the commodity prices received for our oil and natural gas production. The net sales volume of natural gas for the year ended December 31, 2010, was approximately 603,330 MCF with an average price of $4.28 per MCF, versus 575,995 MCF with an average price of $4.09 per MCF for 2009. This represents an increase in net sales volume of 27,335 MCF or 4.7%. This increase was due to higher production volumes of wells drilled and put online during the later part of the year. The net sales volume for oil and condensate (natural gas liquids) production was approximately 6,511 barrels with an average price of $70.95 per barrel for the year ended December 31, 2010, compared to 8,364 barrels at an average price of $52.92 per barrel for the year in 2009. This represents a decrease in net sales volume of 1,853 barrels, or 22.2%.
Oil and gas lease operating expenses decreased by $194,066, or 13.7%, to $1,221,904 for the year ended December 31, 2010, from $1,415,970 for the year in 2009. This decrease was mainly due to continuing cost control measures, lower workover costs and other reduced lease operating costs during 2010. When measuring lease operating costs on a production or lifting cost basis, in 2010, the $1,221,904 equates to a $1.83 per MCFE lifting cost versus a $2.15 per MCFE lifting cost in 2009, a 14.9% decrease.
For the year ended December 31, 2010, turnkey drilling revenues increased $2,806,469 to $7,868,273 from $5,061,804 in 2009, or 55.4%. We also had a $413,164 or 19.2% increase in turnkey drilling and development costs to $2,560,068 in 2010 from $2,146,904 in 2009. In 2010 we drilled nine wells, seven exploratory wells and two developmental wells versus five wells, three exploratory wells and two developmental wells in 2009. Our gross margins, or profits, on drilling depend on our ability to accurately estimate the costs associated with the development of projects in which we sell working interests and to acquire viable properties that can be successfully developed. Costs associated with contract drilling depend on location, well depth, weather, and availability of drilling contractors and equipment. Our gross margin on drilling increased to 67.5% from 57.6% for the years ended December 31, 2010 and 2009, respectively. Gross margin is calculated as the difference between turnkey drilling revenue and turnkey drilling expense. However, management believes that a portion of its impairment losses should
Impairment losses of $500,144 and $1,935,861 were recorded in 2010 and 2009, respectively. In both years, we recorded impairments in fields where year end reserve values were less than the net book values of wells or where lease and land costs that were no longer viable. In 2010, the River Island field was impaired $233,521 due to lower proved producing reserves than current book values. Additionally, two other California fields, Dunnigan Hills, and Rio Vista were impaired $22,118 and $17,931, respectively, also due to lower proved producing reserves than current book values. Our Bowerbank field in California was impaired $24,680 due to lower proved undeveloped reserves than current book values. In 2009, the majority of the impairment, $1,124,293, was recorded in our Utah fields, where various recently drilled wells had significantly lower proved developed nonproducing reserves than originally estimated. Much of these were costs carried over from wells drilled in 2008. Our Elkhorn Slough and East Rice Creek fields, both in California, were impaired $341,098 and $205,173, respectively, due to lower proved producing reserves than their current book values. Two other California fields, the Rio Vista and Bowerbank, were impaired $74,124 and $71,975, respectively, due to lower proved undeveloped reserves than originally estimated. Additionally in 2010 and 2009, we recorded lease impairments of $201,883 and $112,165, respectively, on various capitalized lease and land costs that were no longer viable.
The aggregate of supervisory fees and other income was $682,966 for the year ended December 31, 2010, a decrease of $80,258 (10.5%) from $763,224 during the year in 2009. This decrease was mainly due to the 2009 granting of a seismic license to an industry member for which we were compensated. Supervisory fees are charged in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for reimbursement of expenses associated with the joint accounting for billing, revenue disbursement, and payment of taxes and royalties. These charges are reevaluated each year and adjusted up or down as deemed appropriate by a published report to the industry by Ernst & Young, LLP, Certified Public Accountants. Supervisory fees increased $5,747 or 1.5%, to $394,483 in 2010 from $388,736 in 2009.
Read the The complete Report
