The following table sets forth certain operating information with respect to our oil and gas operations.
The Securities and Exchange Commission requires full-cost companies to calculate a comparison of net capitalized costs of proved oil and gas properties to the discounted present value of future cash flows from the related reserves. The calculation is made using commodity prices at the end of the period held flat for the life of the reserves. If capitalized costs exceed discounted cash flows, the assets are required to be written down to the value of the discounted cash flows. On September 30, 2001, natural gas prices closed at $1.83 per MMBtu. As a result of the low natural gas price, we recorded a $237.7 million non-cash write-down of our oil and gas properties during the third quarter of 2001. The write-down of oil and gas properties did not result in the loss of any proved reserve volumes.
During the third quarter of 2002, hedging transactions increased the average price we received for natural gas by $0.02 per Mcf compared to a net increase of $0.15 per Mcf for the third quarter of 2001. Hedging transactions for natural gas during the first nine months of 2002 increased the average price we received for gas by $0.11 per Mcf compared to a net decrease of $0.21 per Mcf for the comparable 2001 period. Hedging transactions during the first nine months of 2002 increased the average price realized for oil by $0.16 per Bbl.
Production. Oil production during the third quarter of 2002 increased 52% to approximately 1.6 million barrels compared to approximately 1.0 million barrels produced during the third quarter of 2001. Natural gas production during the third quarter of 2002 decreased 6% to approximately 16.7 Bcf from third quarter of 2001 natural gas production of approximately 17.7 Bcf. On a gas equivalent basis, production volumes for the third quarter of 2002, after deferral of approximately 1 Bcfe of net production due to shut-ins for tropical storm Isidore, increased 9% to 26.1 Bcfe compared to third quarter 2001 production of 23.9 Bcfe. Year-to-date 2002 production totaled 4.8 million barrels of oil and 51.5 Bcf of gas while production for the first nine months of 2001 totaled 3.1 million barrels of oil and 52.7 Bcf of gas. The increase in 2002 oil production is primarily due to our acquisition of eight producing properties in December 2001.
During the fourth quarter of 2002, we experienced a Gulf Coast production shut-in related to hurricane Lili, which we estimate will ultimately result in the deferral of approximately 3 Bcfe of fourth quarter production. As a result, we expect net daily production to average 260-270 MMcfe for the fourth quarter of 2002.
Expenses. Normal lease operating expenses during the third quarter of 2002 totaled $15.6 million, or $0.60 per Mcfe, compared to $12.5 million, or $0.52 per Mcfe, for the comparable quarter in 2001. For the first nine months of 2002, normal lease operating expenses totaled $45.9 million, or $0.57 per Mcfe, compared to $35.5 million, or $0.50 per Mcfe, during the comparable period of 2001. Our December 2001 acquisition of eight producing properties increased the number of producing wells and the volume of oil production from 2001 levels. The combination of these factors, coupled with added costs associated with tropical storm Isidore, contributed to the increase in normal lease operating expenses during 2002.
Major maintenance expenses, which represent major repair and workover operations, totaled $5.1 million during the third quarter of 2002 compared to $1.8 million in the third quarter of 2001. Third quarter 2002 major maintenance expenses included workover operations on wells in the South Marsh Island Block 288 and Eugene Island Block 243 fields and platform painting at the East Cameron Block 64 field. We expect to incur major maintenance expenses during the fourth quarter of 2002 due to hurricane Lili; however, Stone believes that most of the costs will be covered by our insurance, which carries a $0.5 million deductible.
Depreciation, depletion and amortization (DD&A) expense on oil and gas properties for the third quarter of 2002 totaled $39.0 million, or $1.50 per Mcfe, compared to $47.1 million, or $1.97 per Mcfe, for the third quarter of 2001. Year-to-date 2002 DD&A expense on oil and gas properties totaled $120.7 million, or $1.50 per Mcfe, compared to $124.8 million, or $1.75 per Mcfe, for the first nine months of 2001. DD&A expense for the third quarter and first nine months of 2002 was positively impacted by higher period-end prices during 2002. For the nine months ended September 30, 2002, Stone estimates that proved reserve additions were less than volumes produced.
We financed fourth quarter 2001 acquisitions with $200.0 million principal amount of 8 1/4% Senior Subordinated Notes due 2011 and borrowings under our bank credit facility. As a result, interest expense, net of amounts capitalized ($2.2 million), for the third quarter of 2002 was $5.9 million, compared to $0.8 million during the third quarter of 2001. For the nine months ended September 30, 2002, interest expense, net of amounts capitalized ($6.4 million), totaled $17.4 million compared to $2.6 million during the comparable period in 2001.
In connection with our merger with Basin Exploration in 2001, we incurred related expenses totaling $0.1 million and $25.7 million during the three- and nine-month periods ended September 30, 2001, respectively.
New Accounting Standards
In July 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations," effective for fiscal years beginning after June 15, 2002. This statement will require us to record the fair value of liabilities, before consideration of salvage, related to future asset retirement obligations in the period the obligation is incurred. We expect to adopt SFAS No. 143 on January 1, 2003. Upon adoption, we will be required to recognize cumulative transition amounts for existing asset retirement obligation liabilities, asset retirement costs and accumulated amortization. An assessment of the impact of SFAS No. 143 on our financial condition and results of operations has yet to be completed. We expect that the adoption of SFAS No. 143 will result in increases in the capitalized costs of our oil and gas properties and the recognition of additional liabilities related to asset retirement obligations.
Hedging Activities
We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," effective January 1, 2001. Under SFAS No. 133, as amended, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. If the instrument qualifies for hedge accounting treatment, it is recorded as either an asset or liability measured at fair value and subsequent changes in the derivative's fair value are recognized in equity through other comprehensive income, to the extent the hedge is considered effective. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet at fair value and changes in fair value are recognized in earnings.
In October 2002, we reached an agreement with Enron North America Corp. to purchase the portion of our fixed price natural gas swap contract settling subsequent to October 2002 for $5.9 million. Other comprehensive income on October 1, 2002 included $2.9 million related to the swap contract that remains to be amortized over the original term of the swap contract, which extends through December 2003.
The following is a breakdown of non-cash derivative expenses for the respective periods:
| | Three Months Ended
September 30,
| | Nine Months Ended
September 30,
| |
|---|
| | 2002
| | 2001
| | 2002
| | 2001
| |
|---|
| | (In thousands) |
|---|
| Amortization of costs of put contracts | $3,916 | | $889 | | $9,259 | | $2,223 | |
| Change in fair market value of swap | (1,249 | ) | - | | 753 | | - | |
| Amortization of other comprehensive income from swap | 670 | | - | | 1,832 | | - | |
| |
| |
| |
| |
| |
| Total non–cash derivative expenses | $3,337 | | $889 | | $11,844 | | $2,223 | |
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At September 30, 2002, the unsettled put contracts were recorded as assets totaling $2.9 million and the unsettled natural gas swap was recorded as a liability totaling $6.6 million. The fair value of the put contracts is determined by the counter-party based upon NYMEX prices.
In August 2002, we entered into gas put contracts with three separate counter-parties for a total of 75,000 MMBtu per day with a floor price of $3.00 per MMBtu. The contracts begin on January 1, 2003 and extend through December 31, 2003. The cost of these contracts totaling approximately $4.6 million will be amortized evenly through earnings over the life of the contracts. These contracts qualify as effective hedges under SFAS No. 133.
Liquidity and Capital Resources
Cash Flow. Net cash flow provided by operating activities for the first nine months of 2002 was $170.0 million compared to $270.8 million reported for the respective period in 2001. The decrease in net cash flow provided by operating activities is primarily attributable to lower oil and gas revenues caused by 26% lower average realized prices on a gas equivalent basis during the first nine months of 2002, offset in part by an increase in oil production volumes for the corresponding period. Net cash flow used in investing activities totaled $172.9 million and $285.9 million during the first nine months of 2002 and 2001, respectively, which primarily represents our investment in oil and gas properties. Net cash flow provided by (used in) financing activities totaled $13.1 million and ($43.4) million for the nine months ended September 30, 2002 and 2001, respectively. The use of financing cash flow during the 2001 period was the result of the $53.0 million repayment of debt made in connection with the termination of Basin Exploration's bank credit facility concurrent with the closing of the merger on February 1, 2001. As a result of these activities, cash and cash equivalents increased from $13.2 million as of December 31, 2001 to $23.3 million as of September 30, 2002.
Capital Expenditures. Capital expenditures during the third quarter of 2002 totaled $48.7 million and included $2.6 million of capitalized salaries, general and administrative expenses and incentive compensation expenses and $2.2 million of capitalized interest. Capital expenditures for the first nine months of 2002 totaled $155.5 million including $7.7 million of capitalized salaries, general and administrative expenses and incentive compensation expenses and $6.4 million of capitalized interest. These investments were financed by cash flow from operations, working capital and borrowings under our bank credit facility.
Budgeted Capital Expenditures. Our current estimated 2002 capital expenditures budget of approximately $210.0 million is allocated 90% to Gulf Coast Basin operations and 10% to Rocky Mountain activities. On July 29, 2002, we entered into a $28.0 million work commitment for at least five wells over a two-year period on the Pinedale Anticline in Wyoming. After the initial $28.0 million investment and the drilling of five wells, we will have earned a 50% working interest in the project area. We spudded the first commitment well during the third quarter of 2002 and expect the remaining wells to be drilled within the terms of the agreement. The Pinedale Anticline is a developing gas field in the Green River Basin in Wyoming.
Based upon our outlook on oil and gas prices and production rates, we expect cash flow from operations to be sufficient to fund the remaining 2002 capital expenditures budget. If oil and gas prices or production rates fall below our current expectations, we believe that the available borrowings under our bank credit facility will be sufficient to fund the capital expenditures in excess of operating cash flow.
Bank Credit Facility. As of November 8, 2002, we had a borrowing base under our credit facility of $300.0 million with availability of $156.7 million in borrowings. The credit facility matures on December 20, 2004. The borrowing base under the credit facility, which is re-determined periodically, is based on an amount established by the bank group resulting from an evaluation of the value of our proved oil and gas reserves.
Production Marketing Risk. The publicly disclosed deteriorating financial conditions and recently reduced credit ratings of certain purchasers of production increase the possibility that we may not receive payment for a portion of our future production. We have attempted to diversify our sales and obtain credit protections such as letters of credit, guarantees and prepayments from certain of our purchasers. We are unable to predict, however, what impact the financial difficulties of certain purchasers may have on our future results of operations and liquidity.
Reserve Replacement Risk. In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rate depends on reservoir characteristics. Gulf of Mexico reservoirs tend to experience steep declines, while declines in other regions after initial flush production tend to be relatively low. Our proved reserves are primarily derived from Gulf of Mexico reservoirs. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production, and corresponding revenues and cash flows, are highly dependent upon our level of success in finding or acquiring additional reserves. While our 2002 drilling program has generated a high drilling success rate, Stone estimates that proved reserve additions were less than volumes produced for the nine months ended September 30, 2002.
Environmental
Compliance with applicable federal, state and local environmental and safety regulations has not required any significant capital expenditures or materially affected our business or earnings. We believe we are in substantial compliance with environmental and safety regulations and foresee no material expenditures in the future; however, we are unable to predict the impact that compliance with future regulations may have on our capital expenditures, earnings, results of operations, financial condition or competitive position.
Defined Terms
Oil and condensate are stated in barrels ("Bbl") or thousand barrels ("MBbl"). Natural gas is stated herein in billion cubic feet ("Bcf"), million cubic feet ("MMcf") or thousand cubic feet ("Mcf"). Oil and condensate are converted to gas at a ratio of one barrel of liquids per six Mcf of gas. Bcfe, MMcfe, and Mcfe represent one billion cubic feet, one million cubic feet and one thousand cubic feet of gas equivalent, respectively. BBtu represents one billion British Thermal Units. An active property is an oil and gas property with existing production. A primary term lease is an oil and gas property with no existing production, in which we have a specific time frame to establish production without losing the rights to explore the property.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our major market risk exposure continues to be the pricing applicable to our oil and gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. In order to manage our exposure to oil and natural gas price declines we occasionally enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production. We do not enter into hedging transactions for trading purposes.
Our hedging policy provides that not more than one-half of our estimated production quantities can be hedged without the consent of the Board of Directors. In August 2002, we entered into additional gas put contracts, which were approved by our Board of Directors, to secure what we believe to be an attractive floor price for a portion of our 2003 gas production. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Hedging Activities for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.
Interest Rate Risk
At September 30, 2002, we had long-term debt outstanding of $436.0 million. Of this amount, $300.0 million, or 69%, bears interest at fixed rates averaging 8.4%. The remaining $136.0 million of debt outstanding at September 30, 2002 bears interest at a floating rate. At September 30, 2002, the weighted average interest rate under our floating-rate debt was 3.2%. Because the majority of our long-term debt at September 30, 2002 was at fixed rates, we consider our interest rate exposure at such date to be minimal. At September 30, 2002, we had no open interest rate hedge positions to reduce our exposure to changes in interest rates.
Since the filing of our Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to interest rates and commodity prices.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our chief executive officer and our chief financial officer, with the participation of other members of our senior management, reviewed and evaluated the effectiveness of the design and operation of Stone's disclosure controls and procedures as of a date within 90 days before the filing of this quarterly report on Form 10-Q. Based on this evaluation, our chief executive officer and chief financial officer believe:
- Stone’s disclosure controls and procedures are designed to ensure that information required to be disclosed by Stone in the reports it files or submits 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; and
- Stone’s disclosure controls and procedures were effective to ensure that material information was accumulated and communicated to Stone’s management, including Stone’s chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Controls
There were no significant changes in Stone's internal controls or, to their knowledge, in other factors that could significantly affect these controls subsequent to the date of their evaluation, nor were there any significant deficiencies or material weaknesses in Stone's internal controls. As a result, no corrective actions were required or undertaken.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C. and Goodrich Petroleum Company-Lafitte, L.L.C. filed civil action number 2000-06437, in Harris County, Texas, against Stone Energy Corporation, seeking seismic data at Lafitte Field and unspecified damages. Subsequently, the same third party that had granted a data use license to Stone granted a similar license to plaintiffs at no cost and provided plaintiffs with the seismic data. We do not expect this matter to have a material adverse effect on our financial condition.
Item 6. Exhibits and Reports on Form 8-K
Date of Event Reported
August 14, 2002 | Item Reported
Item 9* |
| * | | The information in the Form 8-K furnished pursuant to Item 9 is not considered to be “filed” for the purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities of that section. |
SIGNATURE
Pursuant to the requirements 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.
| | STONE ENERGY CORPORATION |
| | |
| Date: November 11, 2002 | By: /s/ James H. Prince
James H. Prince
Senior Vice President, Chief Financial
Officer and Treasurer
(On behalf of Registrant and as
Principal Financial Officer) |
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
I, D. Peter Canty, President and Chief Executive Officer of Stone Energy Corporation, certify that:
- I have reviewed this quarterly report on Form 10-Q of Stone Energy Corporation (the "Registrant");
- Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
- Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this quarterly report;
- The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:
| a) | Designed such disclosure controls and procedures to ensure that material information relating to the Registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; |
| b) | Evaluated the effectiveness of the Registrant's disclosure controls and procedures as of a date within 90 days prior to the filing of this quarterly report (the "Evaluation Date"); and |
| c) | Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; |
- The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the Registrant's auditors and the audit committee of the Registrant's board of directors:
| a) | All significant deficiencies in the design or operation of internal controls which could adversely affect the Registrant's ability to record, process, summarize and report financial data and have identified for the Registrant's auditors any material weakness in internal controls; and |
| b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal controls; and |
- The Registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
| | /s/ D. Peter Canty
Name: D. Peter Canty
Date: November 11, 2002 |
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
I, James H. Prince, Senior Vice President, Chief Financial Officer and Treasurer of Stone Energy Corporation, certify that:
- I have reviewed this quarterly report on Form 10-Q of Stone Energy Corporation (the "Registrant");
- Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
- Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this quarterly report;
- The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:
| a) | Designed such disclosure controls and procedures to ensure that material information relating to the Registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; |
| b) | Evaluated the effectiveness of the Registrant's disclosure controls and procedures as of a date within 90 days prior to the filing of this quarterly report (the "Evaluation Date"); and |
| c) | Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; |
- The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the Registrant's auditors and the audit committee of the Registrant's board of directors:
| a) | All significant deficiencies in the design or operation of internal controls which could adversely affect the Registrant's ability to record, process, summarize and report financial data and have identified for the Registrant's auditors any material weakness in internal controls; and |
| b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal controls; and |
- The Registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
| | /s/ James H. Prince
Name: James H. Prince
Date: November 11, 2002 |
