We adopted SFAS No. 143 on January 1, 2003. Upon adoption, we recognized a credit for a cumulative transition adjustment of $5.3 million, net of tax, for existing asset retirement obligation liabilities, asset retirement costs and accumulated depreciation. In addition, we recorded a $32.1 million increase in the capitalized costs of our oil and gas properties, net of accumulated depreciation, and recognized $76.3 million in additional liabilities related to asset retirement obligations. During the first quarter of 2003, we recognized a non-cash expense of $1.6 million related to the accretion of our asset retirement obligation in accordance with the adoption of SFAS No. 143. As of March 31, 2003, accretion expense represents the only change in the asset retirement obligation since adoption at January 1, 2003. As required by SFAS No. 143, our estimate of our asset retirement obligation does not give consideration to the value that the related assets could have to other parties.
Assuming SFAS No. 143 was adopted as of the beginning of the earliest period presented, the liability for our asset retirement obligation would have been $70.5 million as of January 1, 2002. The following table illustrates the estimated impact SFAS No. 143 would have had on our earnings and earnings per share assuming adoption at the beginning of the earliest period presented:
Note 8 – Stock-Based Compensation
In October 1995, the FASB issued SFAS No. 123, “Accounting for Stock-Based Compensation,” which became effective with respect to us in 1996. Under SFAS No. 123, companies can either record expense based on the fair value of stock-based compensation upon issuance or elect to remain under the current method prescribed by Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” whereby no compensation cost is recognized upon grant if certain requirements are met. The FASB has issued SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure,” which has amended APB Opinion 28,Interim Financial Reporting, to require that public companies provide a tabular presentation similar to that called for in annual statements in condensed quarterly statements if, for any period presented, the intrinsic value method is used. We have continued to account for our stock-based compensation under APB 25. However, we have adopted the disclosure provisions of SFAS No. 148 as presented below.
If the compensation expense for stock-based compensation plans had been determined consistent with the expense recognition provisions under SFAS No. 123, our net income and basic and diluted earnings per common share for the three months ended March 31, 2003 and 2002 would have approximated the pro forma amounts below:
| | Three Months Ended
March 31,
|
|---|
| | 2003
| | 2002
|
|---|
| | (In thousands, except per
share amounts)
(Unaudited)
|
| Net income | $55,858 | | | $6,256 | |
| Add: Stock-based compensation expense included in net income, net of tax | - | | | - | |
| Less: Stock-based compensation expense using fair value method, net of tax | (1,385
| ) | | (1,357
| ) |
| Pro forma net income | $54,473
| | | $4,899
| |
| | | | | | |
| Basic earnings per share | $2.12 | | | $0.24 | |
| Pro forma basic earnings per share | $2.07 | | | $0.19 | |
| | | | | | |
| Diluted earnings per share | $2.11 | | | $0.24 | |
| Pro forma diluted earnings per share | $2.06 | | | $0.18 | |
INDEPENDENT ACCOUNTANTS’ REVIEW REPORT
TO THE STOCKHOLDERS OF
STONE ENERGY CORPORATION:
We have reviewed the accompanying condensed consolidated balance sheet of Stone Energy Corporation (a Delaware corporation) as of March 31, 2003, and the related condensed consolidated statements of operations and cash flows for the three-month periods ended March 31, 2003 and 2002. These financial statements are the responsibility of the Company’s management.
We conducted our reviews in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data, and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, which will be performed for the full year with the objective of expressing an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material modifications that should be made to the accompanying condensed consolidated financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States.
We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet of Stone Energy Corporation as of December 31, 2002, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the year then ended (not presented herein) and in our report dated February 28, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2002, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
New Orleans, Louisiana
May 1, 2003
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
This Form 10-Q and the information referenced herein contain statements that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. We use the terms “Stone,” “Stone Energy,” “Company,” “we,” “us” and “our” to refer to Stone Energy Corporation.
When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, operating risks and other risk factors as described in our 2002 Annual Report on Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Stone Energy Corporation are expressly qualified in their entirety by this cautionary statement.
Overview
Stone Energy Corporation is an independent oil and gas company focused primarily in the Gulf Coast Basin and is engaged in the acquisition and subsequent exploration, development, production and operation of oil and gas properties.
Our business strategy, which has remained consistent since 1990, is to increase production, cash flow and reserves through the acquisition, exploitation and development principally of mature oil and gas properties. Currently, our property base consists of 91 active properties, 58 in the Gulf Coast Basin and 33 in the Rocky Mountains, and 31 primary term leases in the Gulf of Mexico. We serve as operator on 53 of our active properties, which enables us to better control the timing and cost of rejuvenation activities. We believe that there will continue to be opportunities to acquire properties in the Gulf Coast Basin due to the increased focus by many of our competitors on projects away from the onshore and shallow water shelf regions of the Gulf of Mexico.
Critical Accounting Policies
Our 2002 Annual Report on Form 10-K describes the accounting policies that we believe are critical to the reporting of our financial position and operating results and that require management’s most difficult, subjective or complex judgments. Our most significant estimates are:
- remaining proved oil and gas reserves;
- timing of our future drilling activities;
- future costs to develop and abandon our oil and gas properties;
- the fair value of derivative positions; and
- classification of unevaluated property costs.
This quarterly report on Form 10-Q should be read together with the discussion contained in our 2002 Annual Report on Form 10-K regarding these critical accounting policies.
Other Factors Affecting Our Business and Financial Results
In addition to the matters discussed above, our business, financial condition and results of operations are affected by a number of other factors. This report on Form 10-Q should be read in conjunction with the discussion in our 2002 Annual Report on Form 10-K regarding these other risk factors.
Results of Operations
The following table sets forth certain information with respect to our oil and gas operations.
| | Three Months Ended
March 31,
|
|---|
| | 2003
| | 2002
|
|---|
| Production: | | | | | |
| Oil (MBbls) | 1,419 | | | 1,618 | |
| Gas (MMcf) | 16,516 | | | 16,877 | |
| Oil and gas (MMcfe) | 25,030 | | | 26,585 | |
| Sales data (In thousands)(a): | | | | | |
| Oil sales | $47,572 | | | $33,931 | |
| Gas sales | 109,974 | | | 46,599 | |
| Total oil and gas sales | $157,546 | | | $80,530 | |
| Average sales prices (a): | | | | | |
| Oil (per Bbl) | $33.53 | | | $20.97 | |
| Gas (per Mcf) | 6.66 | | | 2.76 | |
| Oil and gas (per Mcfe) | 6.29 | | | 3.03 | |
| Expenses (per Mcfe): | | | | | |
| Normal lease operating expenses (b) | $0.60 | | | $0.55 | |
| Salaries, general and administrative expenses | 0.13 | | | 0.13 | |
| DD&A on oil and gas properties | 1.64 | | | 1.51 | |
| | | | | | |
| (a) Includes the cash effects of hedging |
| (b) Excludes major maintenance expenses |
Net Income. Net income for the first quarter of 2003 increased approximately 790% to $55.9 million, or $2.11 per share, compared to net income reported for the first quarter of 2002 of $6.3 million, or $0.24 per share. The increase in net income was primarily due to the higher average prices we received for our production partially offset by a decline in volumes produced as discussed below. Excluding the cumulative effects of the adoption of and changes in accounting principles, net income for the first quarter of 2003 totaled $54.6 million, or $2.06 per share.
Prices. Prices realized during the first quarter of 2003 averaged $33.53 per barrel of oil and $6.66 per Mcf of gas compared to first quarter 2002 average realized prices of $20.97 per barrel of oil and $2.76 per Mcf of gas. On a gas equivalent basis, prices realized during the first quarter of 2003 were 108% higher than prices realized during the first quarter of 2002. All unit pricing amounts include the cash effects of hedging. During the first quarter of 2003, hedging transactions had no impact on the average realized price we received for our oil and natural gas production. Hedging transactions in the first quarter of 2002 increased the average realized price of natural gas and oil by $0.34 per Mcf and $0.48 per barrel, respectively.
Production. Oil production during the first quarter of 2003 totaled approximately 1,419,000 barrels compared to first quarter 2002 production of 1,618,000 barrels, while natural gas production during the first quarter of 2003 totaled approximately 16.5 Bcf, compared to first quarter 2002 gas production of 16.9 Bcf. On a natural gas equivalent basis, production volumes for the first quarter of 2003 declined 6% to 25.0 Bcfe compared to first quarter 2002 production of 26.6 Bcfe.
Oil and Gas Revenue. As a result of higher realized prices, first quarter 2003 oil and gas revenue increased 96% to $157.5 million, compared to first quarter 2002 oil and gas revenue of $80.5 million.
Expenses. Normal lease operating expenses during the first quarter of 2003 increased to $15.0 million, or $0.60 per Mcfe, compared to $14.6 million, or $0.55 per Mcfe, for the comparable quarter in 2002.
Major maintenance expenses, which represent major repair and workover operations, totaled $2.7 million during the first quarter of 2003 compared to $1.3 million in the first quarter of 2002.
General and administrative expenses for the first quarter of 2003 were $3.3 million, or $0.13 per Mcfe, compared to $3.4 million, or $0.13 per Mcfe, in the first quarter of 2002. Due to Stone’s financial and operational results, incentive compensation expense increased to $0.7 million during the first quarter of 2003 compared to $0.2 million incurred during the first quarter of 2002.
Effective January 1, 2003, management elected to change to the Units of Production (UOP) method of amortizing proved oil and gas property costs versus the formerly used Future Gross Revenue (FGR) method. Under the UOP method, the quarterly provision for depreciation, depletion and amortization (DD&A) is computed by dividing production volumes for the period by the total proved reserves, and applying the respective rate to the net cost of proved oil and gas properties, including future development costs. Under the FGR method, the DD&A rate was calculated by dividing revenue for the period by future gross revenue. Management believes that this change in method is preferable because it removes fluctuations in DD&A expense caused by product pricing volatility within a reporting period and is a method more widely used in the oil and gas industry. The cumulative effect of the change in accounting principle was $4.0 million, net of tax, and was recorded as a non-cash charge during the first quarter of 2003.
Depreciation, depletion and amortization (DD&A) expense on oil and gas properties under the UOP method for the first quarter of 2003 totaled $41.0 million, or $1.64 per Mcfe. Under the FGR method, DD&A expense during the first quarter of 2002 was $40.2 million, or $1.51 per Mcfe. DD&A expense, as adjusted for the new method of accounting, would have been $40.4 million, or $1.52 per Mcfe, for the first quarter of 2002. See Note 7 – Change in Accounting Principles.
During the first quarter of 2003, we recognized a non-cash expense of $1.6 million related to the accretion of our asset retirement obligation in accordance with SFAS No. 143, which was adopted on January 1, 2003.
New Accounting Standard
In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” effective for fiscal years beginning after June 15, 2002. This statement requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the termination of operating assets at the end of an oil and gas property’s useful life. The adoption of SFAS No. 143 requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital.
We adopted SFAS No. 143 on January 1, 2003. Upon adoption, we recognized a credit for a cumulative transition adjustment of $5.3 million, net of tax, for existing asset retirement obligation liabilities, asset retirement costs and accumulated depreciation. In addition, we recorded a $32.1 million increase in the capitalized costs of our oil and gas properties, net of accumulated depreciation, and recognized $76.3 million in additional liabilities related to asset retirement obligations. During the first quarter of 2003, we recognized a non-cash expense of $1.6 million related to the accretion of our asset retirement obligation in accordance with the adoption of SFAS No. 143. As of March 31, 2003, accretion expense represents the only change in the asset retirement obligation since adoption at January 1, 2003. As required by SFAS No. 143, our estimate of our asset retirement obligation does not give consideration to the value that the related assets could have to other parties.
Hedging Activities
We entered into additional natural gas hedges during January 2003 under fixed-price swap contracts for our Rocky Mountain production based upon Inside FERC published prices for deliveries at Kern River and put contracts for our Gulf Coast Basin production. The swap contracts effectively hedge 10,000 MMBtu per day of Rocky Mountain production at a swap price of $3.68 per MMBtu from April 2003 until December 2003 and 15,000 MMBtu per day at a swap price of $3.42 per MMBtu from January 2004 until December 2005. The put contracts effectively hedge an additional 25,000 MMBtu per day of Gulf Coast Basin production with a floor price of $3.50 per MMBtu from March 2003 until December 2003. The put contracts’ cost of approximately $0.5 million will be charged to earnings as the contracts settle.
The following is a breakdown of non-cash derivative expenses for the respective periods:
| | Three Months Ended
March 31,
|
|---|
| | 2003
| | 2002
|
|---|
| | (Unaudited)
(In thousands)
|
| Amortization of costs of put contracts | $1,177 | | | $2,060 | |
| Change in fair market value of swap contract | - | | | 2,362 | |
| Amortization of other comprehensive income from swap | 996
| | | 599
| |
| Total non-cash derivative expenses | $2,173
| | | $5,021
| |
Liquidity and Capital Resources
Cash Flow. Net cash flow provided by operating activities for the three months ended March 31, 2003 was $109.3 million compared to $53.9 million reported in the comparable period in 2002. The increase in net cash flow provided by operating activities was primarily attributable to increased oil and gas revenue caused by higher average realized prices on oil and gas during 2003, offset in part by a 6% decrease in production volumes for the corresponding period.
Net cash flow used in investing activities totaled $81.5 million and $67.7 million during the first quarter of 2003 and 2002, respectively, which primarily represents our investment in oil and gas properties.
Net cash flow provided by (used in) financing activities totaled ($20.0) million and $12.7 million for the three months ended March 31, 2003 and 2002, respectively. During the first quarter of 2003, we used a portion of our excess cash flow to repay $20.0 million of borrowings under our bank credit facility. In total, cash and cash equivalents increased from $27.6 million as of December 31, 2002 to $35.4 million as of March 31, 2003.
We had working capital at March 31, 2003 of $39.7 million. We believe that our working capital balance is not a good indication of our liquidity because it fluctuates as a result of borrowings or repayments under our credit facility and the timing of capital expenditures.
Capital Expenditures. First quarter 2003 additions to oil and gas property costs of $119.1 million included $52.0 million of asset retirement costs in connection with the adoption of SFAS No. 143. Capital expenditures incurred during the first quarter of 2003 totaled $67.1 million, which included $14.3 million of acquisition costs, $3.5 million of capitalized salaries, general and administrative expenses and $2.0 million of capitalized interest. These investments were financed by cash flow from operating activities and working capital.
Budgeted Capital Expenditures. Our current estimated 2003 capital expenditures budget of approximately $240 million is allocated 89% to Gulf Coast operations and 11% to Rocky Mountain activities. We are currently seeking board approval to increase our 2003 capital expenditures budget to approximately $270 million. We expect to drill 51 gross wells during 2003, 37 in the onshore and shallow water offshore regions of the Gulf Coast Basin and 14 in the Rocky Mountains. While the 2003 capital expenditures budget does not include any projected acquisitions, we continue to seek growth opportunities that fit our specific acquisition profile.
Based upon our outlook on oil and gas prices and production rates, we expect cash flow from operations to be more than sufficient to fund the remaining 2003 capital expenditures budget. However, 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. At March 31, 2003, we had $111.0 million of borrowings outstanding under our bank credit facility. Letters of credit totaling $13.1 million have been issued under the facility. During the first quarter of 2003, we repaid $20.0 million of borrowings under the credit facility. We currently have a loan base under the credit facility of $300 million with availability of an additional $175.9 million in borrowings as of May 5, 2003. The credit facility matures on December 20, 2004. Our borrowing base under the credit facility, which is re-determined periodically, is based on an amount established by the bank group after its evaluation of our proved oil and gas reserve values.
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.
Operating Risk. The exploration for and development of oil and gas properties involves a variety of operating risks as described in our 2002 Annual Report on Form 10-K. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks inherent in our business. During 2002, we experienced two separate production interruptions resulting from the two named Gulf of Mexico storms. At the time, we maintained loss of production insurance to protect us against uncontrollable disruptions in production operations from events of this nature. However, we have decided not to renew loss of production coverage effective May 1, 2003, based on our assessment of the cost to retain this policy as compared to the benefits we received as a result of production interruptions caused by these storms.
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 natural 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. MMBtu represents one million British Thermal Units and 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 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 gas price declines, we occasionally enter into oil and 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. See Note 3 – Hedging Activities for a detailed discussion of hedges in place to manage our exposure to oil and gas price declines.
Interest Rate Risk
At March 31, 2003, Stone had long-term debt outstanding of $411.0 million. Of this amount, $300 million, or 73%, bears interest at fixed rates averaging 8.4%. The remaining $111.0 million of debt outstanding at March 31, 2003 bears interest at a floating rate. At March 31, 2003, the weighted average interest rate under our floating-rate debt was approximately 2.7%. Because the majority of our long-term debt at March 31, 2003 was at fixed rates, we consider our interest rate exposure at such date to be minimal. At March 31, 2003, we had no open interest rate hedge positions to reduce our exposure to changes in interest rates.
Since the filing of our 2002 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 the knowledge of our chief executive officer and chief financial officer, 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 6. Exhibits and Reports on Form 8-K
Date of Event Reported
January 24, 2003
February 18, 2003
March 10, 2003
March 10, 2003
March 19, 2003
March 24, 2003 | Item(s) Reported
Item 9*
Item 7 & 9*
Item 7 & 9*
Item 7 & 9*
Item 9*
Item 5 & 7 |
| * | | The information in the Forms 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: May 13, 2003 | By: /s/ James H. Prince
James H. Prince
Senior Vice President, Chief Financial
Officer and Treasurer
(On behalf of the 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 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 weaknesses 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: May 13, 2003 |
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 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 weaknesses 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: May 13, 2003 |
