Stone Energy Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, production and operation of oil and gas properties in the Gulf Coast Basin and Rocky Mountains. The Gulf Coast Basin represents our primary focal area of operation and has been throughout our existence.
We are headquartered in Lafayette, Louisiana, with additional offices in New Orleans, Louisiana, Houston, Texas and Denver, Colorado.
A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below.
On February 1, 2001, the stockholders of Stone Energy Corporation and Basin Exploration, Inc. voted in favor of, and thereby consummated, the combination of the two companies in a tax-free, stock-for-stock transaction accounted for under the Pooling-of-Interests method. Stone issued 7,436,652 shares of common stock. In addition, Stone assumed, and subsequently retired with cash on hand, $48,000 of Basin bank debt. The expenses incurred in relation to the merger totaled $25,785 and $1,297 in 2001 and 2000, respectively.
The following table reconciles certain of our pre-merger operating results with results reflecting the restatement of our financial statements under the Pooling-of-Interest method of accounting:
The financial information above does not purport to be indicative of the results of operations that would have occurred had the merger taken place at the beginning of the earliest period presented or future results of operations.
In accordance with the Pooling-of-Interests method of accounting for business combinations, the financial position and results of operations were combined to give effect to the combination of Stone and Basin as if the merger occurred at the beginning of the earliest period presented. Prior to the merger, Basin accounted for depreciation, depletion and amortization (“DD&A”) of oil and gas properties using the units of production method. In connection with the restatement of Stone’s financial statements on a Pooling-of-Interests basis, Basin’s historical provision for DD&A was restated to conform to the future gross revenue method used by Stone. This restatement included related adjustments to Basin’s historical reduction in carrying value of oil and gas properties recorded at the end of 1998 and their historical provision for income taxes. All periods presented reflect the effects of these adjustments.
We reclassified certain amounts in Basin’s historical financial statements to conform to our presentation.
NOTE 1-- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)
The financial statements include our accounts and the accounts of our wholly owned subsidiary. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation.
Use of Estimates:
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the 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. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization, unevaluated property costs, estimated future net cash flows, cost to abandon oil and gas properties, taxes, reserves of accounts receivable, capitalized employee, general and administrative costs, fair value of financial instruments, the purchase price allocation on properties acquired and contingencies.
Fair Value of Financial Instruments:
The fair value of cash and cash equivalents, accounts receivable, accounts payable to vendors and our variable-rate bank debt approximated book value at December 31, 2002 and 2001. The following table presents the carrying amounts and estimated fair values of our financial instruments at December 31, 2002 and 2001.
| | 2002
| | | 2001
| |
|---|
| | Carrying
Amount
| | Fair
Value
| | | Carrying
Amount
| | Fair
Value
| |
|---|
| | | | | | | | | | |
| 8¼% Senior Subordinated Notes due 2011 | $200,000 | | $208,000 | | | $200,000 | | $201,880 | |
| 8¾% Senior Subordinated Notes due 2007 | 100,000 | | 103,500 | | | 100,000 | | 101,690 | |
| Put contracts | 859 | | 859 | | | 26,207 | | 26,207 | |
| Swap contract | - | | - | | | (5,813 | ) | (5,813 | ) |
The following methods and assumptions were used to estimate the fair value of the financial instruments detailed above. The carrying amount of the bank debt approximated fair value because the interest rate is variable and reflective of market rates. The fair value of the Notes has been estimated based on quotes obtained from brokers. The fair value of the oil and gas price hedges are based upon quotes obtained from the counterparties to the hedge agreements.
Cash and Cash Equivalents:
We consider all highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents.
Oil and Gas Properties:
We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee and general and administrative costs (less any reimbursements for such costs) and interest incurred for the purpose of finding oil and gas is capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Employee, general and administrative costs that are capitalized include salaries and all related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as all other directly identifiable general and administrative costs associated with such activities, such as rentals, utilities and insurance. Fees received from managed partnerships for providing such services are accounted for as a reduction of capitalized costs. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred.
Under the full cost method of accounting, we are required to periodically compare the present value of estimated future net cash flows from proved reserves (based on period-end commodity prices) to the net capitalized costs of proved oil and gas properties. We refer to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows. Due to the impact of low natural gas prices on September 30, 2001, we recorded a $237,741 reduction in the carrying value of our oil and gas properties.
NOTE 1-- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)
Our investment in oil and gas properties is amortized through DD&A using the future gross revenue method whereby the annual provision is computed by dividing revenue earned during the period by future gross revenues at the beginning of the period, and applying the resulting rate to the cost of oil and gas properties, including estimated future development, restoration, dismantlement and abandonment costs. Transactions involving sales of unevaluated properties are recorded as adjustments to oil and gas properties and sales of reserves in place, unless extraordinarily large portions of reserves are involved, are recorded as adjustments to accumulated depreciation, depletion and amortization.
Effective January 1, 2003, management elected to change to the Units of Production method of amortizing proved oil and gas property costs. Under this method, the quarterly provision for DD&A will be computed by dividing production volumes, instead of revenues, for the period by the total proved reserves, instead of future gross revenues, as of the beginning of the period, and similarly applying the respective rate to the net cost of proved oil and gas properties, including future development costs. As a result of the change in accounting principle, we recognized a cumulative transition adjustment of $4,031 as a non-cash charge against our 2003 net income.
Oil and gas properties included $107,473 and $113,372 of unevaluated property and related costs that were not being amortized at December 31, 2002 and 2001, respectively. We believe that a majority of unevaluated properties at December 31, 2002 will be evaluated within 36 months. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. Interest capitalized on unevaluated properties during the years ended December 31, 2002 and 2001 was $8,519 and $6,000, respectively.
On December 31, 2001, Stone completed the acquisition of eight producing oil and gas properties and related assets located in the Gulf of Mexico from Conoco, Inc. The purchase price of approximately $300,000 was financed with net proceeds from the December 2001 offering of $200,000 8¼% Senior Subordinated Notes due 2011 and borrowings under the bank credit facility. This acquisition was accounted for under the purchase method of accounting. Unevaluated property at December 31, 2002 and 2001 included $55,160 and $53,117, respectively, of costs attributable to these properties.
Building and Land:
Building and land are recorded at cost. Our Lafayette office building is being depreciated on the straight-line method over its estimated useful life of 39 years.
Fixed Assets:
Fixed assets at December 31, 2002 and 2001 included approximately $3,553 and $2,593, respectively, of computer hardware and software costs, net of accumulated depreciation. These costs are being depreciated on the straight-line method over an estimated useful life of five years.
Other Assets:
Other assets at December 31, 2002 and 2001 included approximately $8,257 and $9,291, respectively, of deferred financing costs, net of accumulated amortization, related primarily to the issuance of the 8¾% and 8¼% Notes, shelf registration statement and the amendment of the credit facility (see Note 6 – Long-Term Debt). The costs associated with the Notes are being amortized over the life of the Notes using the effective interest method. The costs associated with the credit facility are being amortized on the straight-line method over the term of the facility.
Earnings Per Common Share:
Basic net income per share of common stock was calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the year. Diluted net income per share of common stock was calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the year plus the weighted-average number of outstanding dilutive stock options granted to outside directors, officers and employees. There were approximately 168,000 and 531,000 weighted-average dilutive shares for the years ending December 31, 2002 and 2000, respectively. In 2001, all stock options were considered antidilutive because of the net loss incurred during the year. Options that were considered antidilutive because the exercise price of the stock exceeded the average price for the applicable period totaled approximately 1,064,000 shares and 279,000 shares during 2002 and 2000, respectively.
NOTE 1-- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)
Gas Production Revenue:
We record as revenue only that portion of gas production sold and allocable to our ownership interest in the related well. Any gas production proceeds received in excess of our ownership interest are reflected as a liability in the accompanying balance sheet.
Revenue relating to net undelivered gas production to which we are entitled but for which we have not received payment are not recorded in the financial statements until such amounts are received. These amounts at December 31, 2002, 2001 and 2000 were immaterial.
Effective January 1, 2003, management elected to begin recognizing gas production revenue under the Entitlement method of accounting. Under this method, revenue is deferred for gas deliveries in excess of the company’s net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. The cumulative effect of the adoption of the Entitlement method to be recognized in 2003 is immaterial.
Income Taxes:
Income taxes are accounted for in accordance with the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standard (SFAS) No. 109, “Accounting for Income Taxes.” Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects are capitalized and depreciated, depleted and amortized on the future gross revenue method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, and different reporting methods used in the capitalization of employee, general and administrative and interest expenses.
New Accounting Standard:
In July 2001, the FASB 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 related to future asset retirement obligations in the period the obligation is incurred. We adopted SFAS No. 143 on January 1, 2003. Upon adoption, we recognized a credit for a cumulative transition adjustment of $5,256, net of tax, for existing asset retirement obligation liabilities, asset retirement costs and accumulated depreciation. In addition, we recorded a $32,080 increase in the capitalized costs of our oil and gas properties, net of accumulated depreciation, and recognized $76,270 in additional liabilities related to asset retirement obligations. As required by SFAS No. 143, our estimate of our asset retirement obligation does not give consideration to the value the related assets could have to other parties.
Derivative Instruments and Hedging Activities:
Under SFAS No. 133, as amended, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments qualifying for hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in equity through other comprehensive income, net of related taxes, to the extent the hedge is effective. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings. At December 31, 2002, our put contracts were considered effective cash flow hedges. (See Note 8 – Hedging Activities)
NOTE 2 — ACCOUNTS RECEIVABLE:
In our capacity as operator for our co-venturers, we incur drilling and other costs that we bill to the respective parties based on their working interests. We also receive payments for these billings and, in some cases, for billings in advance of incurring costs. Our accounts receivable are comprised of the following amounts:
| | December 31,
|
|---|
| | 2002
| | 2001
|
|---|
| Accounts Receivable: | | | |
| Other co–venturers | $10,224 | | $11,211 |
| Trade | 64,195 | | 35,371 |
| Officers and employees | 6 | | 4 |
| Unbilled accounts receivable | 375 | | 401 |
| |
| |
|
| | $74,800 | | $46,987 |
| |
| |
|
NOTE 3 — CONCENTRATIONS:
Sales to Major Customers
Our production is sold on month-to-month contracts at prevailing prices. The following table identifies customers from whom we derived 10% or more of our total oil and gas revenue during the following years ended:
| | December 31,
|
|---|
| | 2002
| 2001
| 2000
|
|---|
| Conoco, Inc. | 10% | (a) | (a) |
| Duke Energy Trading and Marketing LLC | 24% | (a) | 11% |
| El Paso Merchant Energy, LP | (a) | 26% | 13% |
| Enron North America Corp | - | 19% | 10% |
| Reliant Services, Inc. | 11% | (a) | (a) |
| | | | |
| (a) less than 10 percent. | | | |
We believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to market future oil and gas production.
At December 31, 2002, Duke Energy Trading and Marketing LLC accounted for 42% of our trade accounts receivable balance.
During the fourth quarter of 2001, we recorded a $2,343 bad debt expense to reserve 100% of production accounts receivable from Enron North America Corp.
Production Volumes
Our four largest fields, South Pelto Block 23, Mississippi Canyon Block 109, Ewing Bank Block 305 and Eugene Island Block 243, accounted for approximately 38% of our total oil and gas production volumes during 2002.
Cash Deposits
Substantially all of our cash balances are in excess of federally insured limits.
NOTE 4 — INVESTMENT IN OIL AND GAS PROPERTIES:
The following table discloses certain financial data relative to our oil and gas producing activities, which are located onshore and offshore the continental United States:
| | Year Ended December 31,
|
|---|
| | 2002
| | 2001
| | 2000
|
|---|
| Oil and gas properties– | | | | | | | | |
| Balance, beginning of year | $2,009,361 | | | $1,368,084 | | | $1,098,940 | |
| Costs incurred during the year: | | | | | | | | |
| Capitalized– | | | | | | | | |
| Acquisition costs, net of sales of unevaluated properties | 14,071 | | | 328,778 | | | 15,086 | |
| Exploratory drilling | 86,063 | | | 176,679 | | | 138,420 | |
| Development drilling | 96,426 | | | 119,426 | | | 98,004 | |
| Employee, general and administrative costs and interest | 19,603 | | | 16,720 | | | 19,234 | |
| Less: overhead reimbursements | (564 | ) | | (326 | ) | | (1,600 | ) |
| |
| |
| |
|
| Total costs incurred during year | 215,599 | | | 641,277 | | | 269,144 | |
| |
| |
| |
|
| Balance, end of year | $2,224,960 | | | $2,009,361 | | | $1,368,084 | |
| |
| |
| |
|
| Charged to expense– | | | | | | | | |
| Operating costs: | | | | | | | | |
| Normal lease operating expenses | $60,952 | | | $47,564 | | | $41,474 | |
| Major maintenance expenses | 15,721 | | | 6,508 | | | 6,538 | |
| |
| |
| |
|
| Total operating costs | 76,673 | | | 54,072 | | | 48,012 | |
| Production taxes | 5,039 | | | 6,408 | | | 7,607 | |
| |
| |
| |
|
| | $81,712 | | | $60,480 | | | $55,619 | |
| |
| |
| |
|
| Unevaluated oil and gas properties– | | | | | | | | |
| Costs incurred during the year: | | | | | | | | |
| Acquisition costs | $11,872 | | | $77,311 | | | $22,760 | |
| Exploration costs | 6,238 | | | - | | | 6,229 | |
| |
| |
| |
|
| | $18,110 | | | $77,311 | | | $28,989 | |
| |
| |
| |
|
| Accumulated depreciation, depletion and amortization– | | | | | | | | |
| Balance, beginning of year | ($1,015,455 | ) | | ($620,510 | ) | | ($511,279 | ) |
| Provision for depreciation, depletion and amortization | (158,265 | ) | | (157,204 | ) | | (109,231 | ) |
| Sale of proved properties | (3,304 | ) | | - | | | - | |
| Write–down of oil and gas properties | - | | | (237,741 | ) | | - | |
| |
| |
| |
|
| Balance, end of year | ($1,177,024 | ) | | ($1,015,455 | ) | | ($620,510 | ) |
| |
| |
| |
|
| Net capitalized costs (proved and unevaluated) | $1,047,936 | | | $993,906 | | | $747,574 | |
| |
| |
| |
|
| DD&A per Mcfe | $1.52 | | | $1.70 | | | $1.10 | |
| |
| |
| |
|
At December 31, 2002 and 2001, unevaluated oil and gas properties of $107,473 and $113,372, respectively, were not subject to depletion. Of the $107,473 in unevaluated costs at December 31, 2002, $18,110 was incurred in 2002 and $89,363 was incurred in prior years. We believe that a majority of unevaluated properties will be evaluated within 36 months.
Effective January 1, 2003, management elected to change to the Units of Production method of amortizing proved oil and gas property costs. Under this method, the quarterly provision for DD&A will be computed by dividing production volumes, instead of revenues, for the period by the total proved reserves, instead of future gross revenues, as of the beginning of the period, and similarly applying the respective rate to the net cost of proved oil and gas properties, including future development costs. As a result of the change in accounting principle, we recognized a cumulative transition adjustment of $4,031, which will be a charge against our 2003 net income.
NOTE 5 — INCOME TAXES:
An analysis of our deferred taxes follows:
| | As of December 31,
| |
|---|
| | 2002
| | | 2001
| |
|---|
| Net operating loss carryforward | $18,010 | | | $9,795 | |
| Statutory depletion carryforward | 4,917 | | | 4,787 | |
| Contribution carryforward | 276 | | | 158 | |
| Capital loss carryforward | 64 | | | 43 | |
| Alternative minimum tax credit carryforward | 812 | | | 812 | |
| Temporary differences: | | | | | |
| Oil and gas properties—full cost | (84,853 | ) | | (48,617 | ) |
| Hedges | 3,071 | | | (4,214 | ) |
| Other | (69 | ) | | 1,838 | |
| Valuation allowance | (276 | ) | | (158 | ) |
| |
| |
|
| | ($58,048 | ) | | ($35,556 | ) |
| |
| |
|
For tax reporting purposes, operating loss carryforwards totaled approximately $51,457 at December 31, 2002. If not utilized, such carryforwards would begin expiring in 2009 and would completely expire by the year 2021. In addition, we had approximately $14,671 in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized.
As of December 31, 2002, a deferred tax asset of $1,556 was included in other current assets.
Reconciliations between the statutory federal income tax rate and our effective income tax rate as a percentage of income before income taxes follow:
| | Year Ended December 31,
|
|---|
| | 2002
| 2001
| 2000
|
|---|
Income tax expense (benefit) computed at the statutory
federal income tax rate | 35% | (35%) | 35% |
| Non-deductible portion of merger expenses | - | 2% | - |
| Other | - | (1%) | - |
| |
|
|
|
| Effective income tax rate | 35% | (34%) | 35% |
| |
|
|
|
Income tax expense (benefit) allocated to accumulated other comprehensive income amounted to $6,604 and ($4,036) for 2002 and 2001, respectively.
NOTE 6 — LONG-TERM DEBT:
Long-term debt consisted of the following at:
| | December 31,
|
|---|
| | 2002
| | 2001
|
|---|
| 8¼% Senior subordinated notes due 2011 | $200,000 | | $200,000 |
| 8¾% Senior subordinated notes due 2007 | 100,000 | | 100,000 |
| Bank debt | 131,000 | | 126,000 |
| |
| |
|
| Total long–term debt | $431,000 | | $426,000 |
| |
| |
|
On December 5, 2001, we issued $200,000 8¼% Senior Subordinated Notes due 2011. The Notes were sold at par value and we received net proceeds of $195,500. There are no sinking fund requirements and the Notes are redeemable at our option, in whole but not in part, at any time before December 15, 2006 at a Make-Whole Amount. Beginning December 15, 2006, the Notes are redeemable at our option, in whole or in part, at 104.125% of their principal amount and thereafter at prices declining annually to 100% on and after December 15, 2009. In addition, before December 15, 2004, we may redeem up to 35% of the aggregate principal amount of the Notes issued with net proceeds from an equity offering at 108.25%. The Notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments. At December 31, 2002, $746 had been accrued in connection with the June 15, 2003 interest payment.
At December 31, 2002, long-term debt included $100,000 of 8¾% Senior Subordinated Notes due 2007 and there were no minimum principal payments due until maturity in 2007. At December 31, 2002, $2,601 had been accrued in connection with the March 15, 2003 interest payment. The Notes were sold at a discount for an aggregate price of $99,283. There are no sinking fund requirements on the Notes and they are redeemable at our option, in whole or in part, at 104.375% of their principal amount beginning September 15, 2002, and thereafter at prices declining annually to 100% on and after September 15, 2005. The Notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments.
At December 31, 2002, we had $131,000 of borrowings outstanding under our bank credit facility and letters of credit totaling $13,084 had been issued pursuant to the facility. During December 2001, we increased our credit facility to $350,000. The amended credit facility matures on December 20, 2004. At December 31, 2002, we had a borrowing base under the amended credit facility of $300,000, with availability of an additional $155,916 of borrowings. The weighted average interest rate under the amended credit facility was approximately 2.8% at December 31, 2002. Interest rates are tied to LIBOR rates plus a margin that fluctuates based upon the ratio of aggregate outstanding borrowings and letters of credit exposure to the total borrowing base. Commitment fees are computed and payable quarterly at the rate of 50 basis points of borrowing availability. The borrowing base limitation is re-determined periodically and is based on a borrowing base amount established by the banks for our oil and gas properties.
Under the financial covenants of our credit facility, we must (i) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the amended credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (ii) maintain a consolidated tangible net worth of a least $350,000 as of September 30, 2001, which is adjusted for future earnings and cash proceeds from equity offerings. In addition, the credit facility places certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of ownership and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends.
NOTE 7 — TRANSACTIONS WITH RELATED PARTIES:
James H. Stone and Joe R. Klutts, both directors of Stone Energy, collectively own 9% of the working interest in certain wells drilled on Section 19 on the east flank of Weeks Island Field. These interests were acquired at the same time that our predecessor company acquired its interests in Weeks Island Field. In their capacity as working interest owners, they are required to pay their proportional share of all costs and are entitled to receive their proportional share of revenues.
Our interests in certain oil and gas properties are burdened by net profits interests and overriding royalty interests granted at the time of acquisition to certain of our officers. Such net profit interest owners do not receive any cash distributions until we have recovered all acquisition, development, financing and operating costs. D. Peter Canty, chief executive officer, and James H. Prince, chief financial officer, remain net profit interest owners. Amounts paid to these officers under the remaining net profits arrangement amounted to $934, $1,777 and $1,085 in 2002, 2001 and 2000, respectively. In addition, Michael E. Madden, our Vice President of Engineering, was granted an overriding royalty interest in some of our properties by an independent third party. At the time he was granted this interest, he was serving us as an independent engineering consultant. The amount paid to Michael E. Madden during 2002 under the overriding royalty arrangement totaled $61. Mr. Madden was promoted to Vice President of Engineering in March of 2002.
In June 2000, we purchased property that adjoins our Lafayette office from StoneWall Associates for an independently appraised value of approximately $540. Two of our directors, James H. Stone and Joe R. Klutts, are partners of StoneWall Associates.
Joe R. Klutts, one of our directors, received $17, $56 and $41 during 2002, 2001 and 2000, respectively, in consulting fees after retiring, February 1, 2000, as an employee of Stone.
Laborde Marine Lifts, Inc., of which John P. Laborde, one of our directors, is Chairman, provided services to us during 2000. The value of these services was approximately $75. Additionally, Laborde Marine LLC, in which Mr. Laborde’s son has an interest, provided services to us during 2002 and 2001 in the amount of $1,717 and $255, respectively. John P. Laborde has no interest in Laborde Marine LLC.
The law firm of Gordon, Arata, McCollam, Duplantis and Eagan, of which B.J. Duplantis, one of our directors, is a Senior Partner, provided legal services for us during 2002, 2001 and 2000. The value of these services totaled approximately $14, $20 and $9 during 2002, 2001 and 2000, respectively.
NOTE 8 — HEDGING ACTIVITIES:
We enter into hedging transactions to secure a price for a portion of future production that is acceptable at the time at which the transaction is entered. The primary objective of these activities is to reduce our exposure to the possibility of declining oil and gas prices during the term of the hedge. These hedges are designated as cash flow hedges when entered into. We do not enter into hedging transactions for trading purposes. Monthly settlements of these contracts are reflected in revenue from oil and gas production. Under generally accepted accounting principles, beginning January 1, 2001, in order to consider these futures contracts as hedges, (i) we must designate the futures contract as a hedge of future production and (ii) the contract must be effective at reducing our exposure to the risk of changes in prices. Changes in the market values of futures contracts treated as hedges are not recognized in income until the hedged item is also recognized in income. If the above criteria are not met, we will record the market value of the contract at the end of each month and recognize a related increase or decrease in non-cash derivative expenses. Any amount received or paid to terminate a contract reduces the asset or liability, respectively, associated with the contract. Changes in market value previously recognized in other comprehensive income is amortized to earnings over the remaining life of the original contract.
We adopted SFAS No. 133 effective January 1, 2001. Upon adoption of SFAS No. 133, as amended, the after-tax increase in fair value over historical cost of our oil put contracts of $1,736 was a transition adjustment that was recorded as a gain in equity through other comprehensive income.
At December 31, 2002, our gas puts were reflected as assets at a fair value of $859. Our gas put contracts are with Bank of America, N.A., J. Aron & Company and Bank of Montreal. Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contracts represents our maximum cash exposure. We are not obligated to make any further payments under the put contracts regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if NYMEX prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above that floor. Our put contracts are considered effective hedges under SFAS No. 133 and all changes in fair value are recorded, net of taxes, in other comprehensive income.
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 $5,917. Accumulated other comprehensive income on December 31, 2002 included $2,361 related to the swap contract that will be amortized during 2003.
Because over 90% of our production has historically been derived from the Gulf Coast Basin, we believe that fluctuations in NYMEX prices will closely match changes in the market prices we receive for our production. Oil contracts typically settle using the average of the daily closing prices for a calendar month. Natural gas contracts typically settle using the average closing prices for near month NYMEX futures contracts for the three days prior to the settlement date.
The following table shows our hedging positions as of January 1, 2003:
| | Natural Gas Puts
|
|---|
| | Volume
(BBtus)
| | Floor
| | Unamortized
Cost
|
|---|
| 2003 | 27,375 | | $3.00 | | $4,563 |
We entered into additional natural gas hedges during January 2003 under fixed-price swap contracts based upon deliveries in the Rocky Mountains and put contracts for Gulf Coast Basin production. The swap contracts effectively hedge 10,000 MMBtu per day at a swap price of $3.68 from April 2003 until December 2003 and 15,000 MMBtu per day at a swap price of $3.42 from January 2004 until December 2005. The put contracts effectively hedge 25,000 MMBtu per day with a floor price of $3.50 per MMBtu from March 2003 until December 2003. The put contracts’ cost of approximately $516 will be charged to earnings as the contracts settle.
During 2002 and 2001, we recognized $15,968 and $2,604, respectively, of non-cash derivative expenses. The components of non-cash derivative expenses were as follows:
| | Year Ended December 31,
|
|---|
| | 2002
| | 2001
| |
|---|
| Amortization of cost of put contracts | $13,175 | | $3,112 | |
| Change in fair value of swap contract | 104 | | (339 | ) |
| Amortization of other comprehensive income | 2,689 | | (169 | ) |
| |
| |
| |
| | $15,968 | | $2,604 | |
| |
| |
| |
For the years ended December 31, 2002, 2001 and 2000, we realized net increases (decreases) in oil and gas revenue related to hedging transactions of $5,953, ($1,819) and ($47,899), respectively.
NOTE 9 — COMMON STOCK:
On February 1, 2001, our stockholders approved a proposal to amend our certificate of incorporation, in connection with the Basin merger, increasing the number of authorized shares of our common stock from 25,000,000 to 100,000,000.
NOTE 10 — COMMITMENTS AND CONTINGENCIES:
On July 29, 2002, we entered into a $28,000 work commitment for at least five wells over a two-year period on the Pinedale Anticline in the Green River Basin in Wyoming. After the initial $28,000 investment and the drilling of five wells, we will have earned a 50% working interest in the project area. As of December 31, 2002, $7,086 had been invested in two wells under the original work commitment.
We lease office facilities in New Orleans, Louisiana, Denver, Colorado and two locations in Houston, Texas under the terms of long-term, non-cancelable leases expiring on April 4, 2003, March 15, 2005 and December 31, 2004 and March 31, 2006, respectively. We also lease automobiles under the terms of non-cancelable leases expiring at various dates through 2005. The minimum net annual commitments under all leases, subleases and contracts noted above at December 31, 2002 were as follows:
| 2003 | $947 |
| 2004 | 912 |
| 2005 | 585 |
| 2006 | 130 |
| 2007 | - |
| Thereafter | - |
Payments related to our lease obligations for the years ended December 31, 2002, 2001 and 2000 were approximately $889, $1,280 and $1,146, respectively. We sublease office space to third parties, and for the years ended 2002, 2001 and 2000, we recorded related receipts of $239, $285 and $181, respectively. Minimum lease rentals to be received from the sublease of office space is $239 for each of the years ended December 31, 2003, 2004 and 2005.
We are contingently liable to surety insurance companies in the aggregate amount of $40,966 relative to bonds issued on our behalf to the United States Department of the Interior Minerals Management Service (MMS), federal and state agencies and certain third parties from which we purchased oil and gas working interests. The bonds represent guarantees by the surety insurance companies that we will operate in accordance with applicable rules and regulations and perform certain plugging and abandonment obligations as specified by applicable working interest purchase and sale agreements.
We are also named as a defendant in certain lawsuits and are a party to certain regulatory proceedings arising in the ordinary course of business. We do not expect these matters, individually or in the aggregate, to have a material adverse effect on our financial condition.
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.
OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under OPA and a final rule adopted by the MMS in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must demonstrate financial responsibility in amounts ranging from at least $10,000 in specified state waters to at least $35,000 in OCS waters, with higher amounts of up to $150,000 in certain limited circumstances where the MMS believes such a level is justified by the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under the MMS’s final rule. We do not anticipate that we will experience any difficulty in continuing to satisfy the MMS’s requirements for demonstrating financial responsibility under OPA and the MMS’s regulations.
NOTE 11 — EMPLOYEE BENEFIT PLANS:
We have entered into deferred compensation and disability agreements with certain of our officers whereby we have purchased split-dollar life insurance policies to provide certain retirement and death benefits for certain of our officers and death benefits payable to us. The aggregate death benefit of the policies was $2,890 at December 31, 2002, of which $1,975 was payable to certain officers or their beneficiaries and $915 was payable to us. Total cash surrender value of the policies, net of related surrender charges at December 31, 2002, was approximately $899. Additionally, the benefits under the deferred compensation agreements vest after certain periods of employment, and at December 31, 2002, the liability for such vested benefits was approximately $808. The difference between the actuarial determined liability for retirement benefits or the vested amounts, where applicable, and the net cash surrender value has been recorded as an other long-term asset.
We have adopted a series of incentive compensation plans designed to align the interests of our directors and employees with those of our stockholders. The following is a brief description of each of the plans:
| i. | | The Annual Incentive Compensation Program provides for an annual cash incentive bonus that ties incentives to the annual return on our common stock, to a comparison of the price performance of our common stock to the average quarterly returns on the shares of stock of a peer group of companies with which we compete and to the growth in our net earnings per share, net cash flows and net asset value. Incentive bonuses are awarded to participants based upon individual performance factors. Stone incurred expenses of $851, $523 and $1,722, net of amounts capitalized, for the years ended December 31, 2002, 2001 and 2000, respectively, related to incentive compensation bonuses paid under this program. |
| | | In February 2003, our board of directors approved and adopted the Revised Annual Incentive Compensation Plan. The Plan will provide for annual cash incentive bonuses that are tied to the annual return on our common stock, to a stock performance comparison to our peers, to growth in our earnings and net asset value per share and to the achievement of certain strategic objectives as defined by our board of directors on an annual basis. |
| ii. | | The 2001 Amended and Restated Stock Option Plan provides for 3,225,000 shares of common stock to be reserved for issuance pursuant to this plan. Under this plan, we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options to all employees and directors. All such options must have an exercise price of not less than the fair market value of the common stock on the date of grant and may not be re-priced without stockholder approval. Stock options to all employees vest ratably over a five-year service-vesting period and expire ten years subsequent to award. Stock options issued to non-employee directors vest ratably over a three-year service-vesting period and expire five years subsequent to award. The number of shares reserved for issuance pursuant to the 2001 Amended and Restated Stock Option Plan does not include approximately 348,000 outstanding stock options assumed on February 1, 2001 in connection with the merger with Basin Exploration, Inc. |
| iii. | | The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee’s deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the directions of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the years ended December 31, 2002, 2001 and 2000, Stone contributed $645, $688 and $445, respectively, to the plan. |
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 Accounting Principles Board Opinion No. 25 (“APB 25”) method whereby no compensation cost is recognized upon grant if certain requirements are met. We have continued to account for our stock-based compensation under APB 25. However, disclosures as if we had adopted the expensed recognition provisions under SFAS No. 123 are 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 2002, 2001 and 2000 net income (loss) and basic and diluted earnings (loss) per common share would have approximated the pro forma amounts below:
| | Year Ended December 31,
|
|---|
| | 2002
| | 2001
| | 2000
|
|---|
| | As
Reported
| Pro
Forma
| | As
Reported
| Pro
Forma
| | As
Reported
| Pro
Forma
|
|---|
| Net income (loss) | $55,399 | $49,986 | | ($71,375) | ($76,659) | | $126,457 | $121,248 |
| Earnings (loss) per common share: | |
| Basic | $2.10 | $1.90 | | ($2.73) | ($2.94) | | $4.90 | $4.70 |
| Diluted | $2.09 | $1.89 | | ($2.73) | ($2.94) | | $4.80 | $4.60 |
A summary of stock options as of December 31, 2002, 2001 and 2000 and changes during the years ended on those dates is presented below.
| | Year Ended December 31,
|
|---|
| | 2002
| | 2001
| | 2000
|
|---|
| | Number
of
Options
| Wgtd.
Avg.
Exer.
Price
| | Number
of
Options
| Wgtd.
Avg.
Exer.
Price
| | Number
of
Options
| Wgtd.
Avg.
Exer.
Price
|
|---|
| Outstanding at beginning of year | 2,058,531 | | $38.04 | | 1,880,077 | | $34.39 | | 1,771,668 | | $27.22 |
| Granted | 625,500 | | 34.23 | | 588,200 | | 48.72 | | 455,045 | | 51.92 |
| Expired | (103,892 | ) | 44.35 | | (163,861 | ) | 47.18 | | (13,000 | ) | 23.95 |
| Exercised | (160,582 | ) | 24.55 | | (245,885 | ) | 28.81 | | (333,636 | ) | 20.52 |
| |
| | | |
| | | |
| | |
| Outstanding at end of year | 2,419,557 | | $37.68 | | 2,058,531 | | $38.04 | | 1,880,077 | | $34.39 |
| Options exercisable at year–end | 1,082,536 | | 32.77 | | 963,761 | | 27.95 | | 808,072 | | 24.48 |
| Options available for future grant | 353,550 | | | | 910,750 | | | | 957,250 | | |
Weighted average fair value of
options granted during the year | $16.12 | | | | $23.86 | | | | $28.65 | | |
The weighted average fair value of each option granted during the periods presented is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: (a) dividend yield of 0%, (b) expected volatility of 45.10%, 44.24% and 45.72% in the years 2002, 2001 and 2000, respectively, (c) risk-free interest rate of 3.11%, 4.88% and 6.76% in the years 2002, 2001 and 2000, respectively, and (d) expected life of six years for employee options and four years for director options.
The following table summarizes information regarding stock options outstanding at December 31, 2002:
| | Options Outstanding
| | Options Exercisable
|
|---|
Range of
Exercise
Prices
| Options
Outstanding
at 12/31/02
| Wgtd. Avg.
Remaining
Contractual Life
| Wgtd. Avg.
Exercise
Price
| | Options
Exercisable
at 12/31/02
| Wgtd. Avg.
Exercise
Price
|
|---|
| $9 – $20 | 157,200 | 1.8 years | $12.31 | | 157,200 | $12.31 |
| 20 – 30 | 416,250 | 4.3 years | 23.72 | | 399,250 | 23.57 |
| 30 – 40 | 1,058,485 | 8.4 years | 34.98 | | 251,340 | 36.38 |
| 40 – 50 | 190,500 | 7.9 years | 44.85 | | 59,300 | 45.62 |
| 50 – 61.93 | 597,122 | 7.0 years | 56.59 | | 215,446 | 60.00 |
| |
| | | |
| |
| | 2,419,557
| 6.9 years | 37.68 | | 1,082,536
| 32.77 |
NOTE 12 — OIL AND GAS RESERVE INFORMATION – UNAUDITED:
Our net proved oil and gas reserves at December 31, 2002 have been estimated by independent petroleum consultants in accordance with guidelines established by the Securities and Exchange Commission (“SEC”). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.
The following table sets forth an analysis of the estimated quantities of net proved and proved developed oil (including condensate) and natural gas reserves, all of which are located onshore and offshore the continental United States:
| | Oil in
MBbls
| | Natural
Gas in
MMcf
|
|---|
| Proved reserves as of December 31, 1999 | 35,213 | | | 385,667 | |
| Revisions of previous estimates | (3,568 | ) | | (10,499 | ) |
| Extensions, discoveries and other additions | 6,375 | | | 85,534 | |
| Purchase of producing properties | 54 | | | 7,394 | |
| Production (1) | (4,449 | ) | | (69,572 | ) |
| |
| |
|
| Proved reserves as of December 31, 2000 | 33,625 | | | 398,524 | |
| Revisions of previous estimates | (1,703 | ) | | (2,876 | ) |
| Extensions, discoveries and other additions | 2,727 | | | 52,742 | |
| Purchase of producing properties | 24,765 | | | 59,849 | |
| Production (1) | (4,023 | ) | | (65,570 | ) |
| |
| |
|
| Proved reserves as of December 31, 2001 | 55,391 | | | 442,669 | |
| Revisions of previous estimates | 905 | | | 2,378 | |
| Extensions, discoveries and other additions | 2,101 | | | 59,785 | |
| Purchase of producing properties | 188 | | | 240 | |
| Sale of reserves | (329 | ) | | (726 | ) |
| Production (1) | (6,237 | ) | | (65,694 | ) |
| |
| |
|
| Proved reserves as of December 31, 2002 | 52,019 | | | 438,652 | |
| |
| |
|
| Proved developed reserves: | | | | | |
| | | | |
| as of December 31, 2000 | 25,374 | | | 307,320 | |
| |
| |
|
| as of December 31, 2001 | 43,094 | | | 351,269 | |
| |
| |
|
| as of December 31, 2002 | 39,772 | | | 334,692 | |
| |
| |
|
| (1) Excludes gas production volumes related to the volumetric production payment. |
The following tables present the standardized measure of future net cash flows related to proved oil and gas reserves together with changes therein, as defined by the FASB. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the table below, represent the fair value of our estimated oil and gas reserves. As required by the SEC, we determine estimated future net cash flows using period-end market prices for oil and gas without considering hedge contracts in place at the end of the period. The average 2002 year-end product prices for all of our properties were $30.41 per barrel of oil and $4.86 per Mcf of gas. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
NOTE 12 — OIL AND GAS RESERVE INFORMATION – UNAUDITED: (Continued)
| | Standardized Measure
Year Ended December 31,
|
|---|
| | 2002
| | 2001
| | 2000
|
|---|
| Future cash flows | $3,713,318 | | | $2,274,665 | | | $4,902,297 | |
| | | | | | |
| Future production costs | (581,539 | ) | | (481,874 | ) | | (451,935 | ) |
| | | | | | |
| Future development costs | (414,518 | ) | | (285,568 | ) | | (249,598 | ) |
| | | | | | |
| Future income taxes | (645,160 | ) | | (212,883 | ) | | (1,392,078 | ) |
| |
| |
| |
|
| Future net cash flows | 2,072,101 | | | 1,294,340 | | | 2,808,686 | |
| | | | | | |
| 10% annual discount | (697,391 | ) | | (385,764 | ) | | (825,937 | ) |
| |
| |
| |
|
| Standardized measure of discounted future net cash flows | $1,374,710 | | | $908,576 | | | $1,982,749 | |
| |
| |
| |
|
| | Changes in Standardized Measure
Year Ended December 31,
|
|---|
| | 2002
| | 2001
| | 2000
|
|---|
| Standardized measure at beginning of year | $908,576 | | | $1,982,749 | | | $691,481 | |
Sales and transfers of oil and gas produced, net of
production costs | (289,830 | ) | | (333,200 | ) | | (368,243 | ) |
| Changes in price, net of future production costs | 862,253 | | | (2,097,695 | ) | | 1,784,727 | |
Extensions and discoveries, net of future production
and development costs | 240,056 | | | 134,876 | | | 656,944 | |
Changes in estimated future development costs, net of
development costs incurred during the period | (43,607 | ) | | 61,994 | | | 30,608 | |
| Revisions of quantity estimates | 22,146 | | | (19,982 | ) | | (162,462 | ) |
| Accretion of discount | 103,880 | | | 294,179 | | | 83,064 | |
| Net change in income taxes | (279,829 | ) | | 828,820 | | | (819,893 | ) |
| Purchases of reserves in–place | 3,374 | | | 314,394 | | | 48,752 | |
| Sales of reserves in–place | (1,403 | ) | | - | | | - | |
| Changes in production rates due to timing and other | (150,906 | ) | | (257,559 | ) | | 37,771 | |
| |
| |
| |
|
| Standardized measure at end of year | $1,374,710 | | | $908,576 | | | $1,982,749 | |
| |
| |
| |
|
NOTE 14 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED:
| | Revenue
| | Expenses
| | Net
Income (Loss)
| | Basic
Earnings (Loss)
Per Share
| Diluted
Earnings (Loss)
Per Share
|
|---|
| 2002 | | | | | | | | | | | |
| First Quarter | $80,530 | | $74,274 | | $6,256 | | | $0.24 | | $0.24 | |
| Second Quarter | 100,438 | | 84,454 | | 15,984 | | | 0.61 | | 0.60 | |
| Third Quarter | 94,523 | | 80,830 | | 13,693 | | | 0.52 | | 0.52 | |
| Fourth Quarter | 102,004 | | 82,538 | | 19,466 | | | 0.74 | | 0.74 | |
| |
| |
| |
| | | | | | |
| | $377,495 | | $322,096 | | $55,399 | | | $2.10 | | $2.09 | |
| |
| |
| |
| | | | | | |
| 2001 | | | | | | | | | | | |
| First Quarter | $142,994 | | $103,735 | | $39,259 | | | $1.51 | | $1.49 | |
| Second Quarter | 106,011 | | 76,943 | | 29,068 | | | 1.11 | | 1.10 | |
| Third Quarter | 82,366 | | 227,434 | | (145,068 | ) | | (5.54 | ) | (5.54 | ) |
| Fourth Quarter | 64,128 | | 58,762 | | 5,366 | | | 0.20 | | 0.20 | |
| |
| |
| |
| | | | | | |
| | $395,499 | | $466,874 | | ($71,375 | ) | | ($2.73 | ) | ($2.73 | ) |
| |
| |
| |
| | | | | | |
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as used in this Form 10-K. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.
Active property. An oil and gas property with existing production.
BBtu. One billion Btus.
Bcf. One billion cubic feet of gas.
Bcfe. One billion cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six mcf of natural gas.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
Finding costs. Costs associated with acquiring and developing proved oil and gas reserves which are capitalized pursuant to generally accepted accounting principles, excluding any capitalized general and administrative expenses.
Gross acreage or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
LIBOR. Represents the London Inter-Bank Overnight Rate of interest.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of gas.
Mcfe. One thousand cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six mcf of natural gas.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet of gas.
MMcfe. One million cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six mcf of natural gas.
MMcfe/d. One million cubic feet of gas equivalent per day.
Make-Whole Amount. The greater of 104.125% of the principal amount of the 8¼% Notes and the sum of the present values of the remaining scheduled payments of principal and interest discounted to the date of redemption on a semiannual basis at the applicable treasury rate plus 50 basis points.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.
GLOSSARY OF CERTAIN INDUSTRY TERMS: (Continued)
Net profits interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production subject to production costs.
Overriding royalty interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production free of production and capital costs.
Pooling-of-Interests. An accounting method for business combinations in which the financial statements and results of operations are prepared as if the companies had been combined at the beginning of the earliest period shown. In addition, the assets and liabilities of the combining companies are carried forward to the combined entity at book value.
Present value. When used with respect to oil and gas reserves, present value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
Primary term lease. An oil and gas property with no existing production, in which Stone has a specific time frame to establish production without losing the rights to explore the property.
Production payment. An obligation of the purchaser of a property to pay a specified portion of future gross revenues, less related production taxes and transportation costs, to the seller of the property.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on developed acreage where the subject reserves cannot be recovered without drilling additional wells.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.
Volumetric production payment. An obligation of the purchaser of a property to deliver a specific volume of production, free and clear of all costs, to the seller of the property.
Working interest. An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.
EXHIBIT INDEX
|
|---|
| | Exhibit
Number
| Description
| |
| | 3.1 – | Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
|
| | 3.2 – | Restated Bylaws of the Registrant (incorporated by reference to Exhibit 3.2 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
|
| | 3.3 – | Certificate of Amendment of the Certificate of Incorporation of Stone Energy Corporation, dated February 1, 2001 (incorporated by reference to Exhibit 4.1 to the Registrant's Form 8-K, filed February 7, 2001).
|
| | 4.1 – | Rights Agreement, with exhibits A, B and C thereto, dated as of October 15, 1998, between Stone Energy Corporation and ChaseMellon Shareholder Services, L.L.C., as Rights Agent (incorporated by reference to Exhibit 4.1 to the Registrant's Registration Statement on Form 8-A (File No. 001-12074)).
|
| | 4.2 – | Indenture between Stone Energy Corporation and Texas Commerce Bank, National Association dated as of September 19, 1997 (incorporated by reference to Exhibit 4.1 to the Registrant's Registration Statement on Form S-4 dated October 22, 1997 (File No. 333-38425)).
|
| | 4.3 – | Amendment No. 1, dated as of October 28, 2000, to Rights Agreement dated as of October 15, 1998, between Stone Energy Corporation and ChaseMellon Shareholder Services, L.L.C., as Rights Agent (incorporated by reference to Exhibit 4.4 to the Registrant's Registration Statement on Form S-4 (Registration No. 333-51968)).
|
| | 4.4 – | Indenture between Stone Energy Corporation and JPMorgan Chase Bank dated December 10, 2001 (incorporated by reference to Exhibit 4.4 to the Registrant's Registration Statement on Form S-4 (Registration No. 333-81380)).
|
| | †10.1 – | Stone Energy Corporation 1993 Nonemployee Directors' Stock Option Plan (incorporated by reference to Exhibit 10.1 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
|
| | †10.2 – | Deferred Compensation and Disability Agreements between TSPC and D. Peter Canty dated July 16, 1981, and between TSPC and Joe R. Klutts and James H. Prince dated August 23, 1981 and September 20, 1981, respectively (incorporated by reference to Exhibit 10.8 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
|
| | †10.3 – | Conveyances of Net Profits Interests in certain properties to D. Peter Canty and James H. Prince (incorporated by reference to Exhibit 10.9 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
|
| | †10.4 – | Deferred Compensation and Disability Agreement between TSPC and E. J. Louviere dated July 16, 1981 (incorporated by reference to Exhibit 10.10 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)).
|
| | †10.5 – | Stone Energy Corporation 2000 Amended and Restated Stock Option Plan (incorporated by reference to Appendix A to the Registrant's Definitive Proxy Statement on Schedule 14A for Stone's 2000 Annual Meeting of Stockholders (File No. 001-12074)).
|
| | †10.6 – | Stone Energy Corporation Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.14 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 (File No. 001-12074)).
|
| | †10.7 – | Stone Energy Corporation Amendment to the Annual Incentive Compensation Plan dated January 15, 1997 (incorporated by reference to Exhibit 10.9 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 001-12074)).
|
| | 10.8 – | Fourth Amended and Restated Credit Agreement between the Registrant, the financial institutions named therein and Bank of America, N.A., as administrative agent, dated as of December 20, 2001 (incorporated by reference to Exhibit 10.3 to the Registrant's Registration Statement on Form S-4 (Registration No. 333-81380)).
|
| | †10.9 – | Stone Energy Corporation 2001 Amended and Restated Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Registrant's Registration Statement on Form S-8 (Registration No. 333-64448)).
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| | †*10.10 – | Stone Energy Corporation Revised Annual Incentive Compensation Plan.
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| | 16.1 – | Letter of Arthur Andersen LLP, dated June 26, 2002, regarding change in certifying accountant (incorporated by reference to Exhibit 16.1 to the Registrant's Form 8-K, filed June 27, 2002).
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| | *21.1 – | Subsidiaries of the Registrant.
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| | *23.1 – | Consent of Ernst & Young LLP.
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| | *23.2 – | Consent of Atwater Consultants, Ltd.
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| | *23.3 – | Consent of Cawley, Gillespie & Associates, Inc.
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| | *23.4 – | Consent of Ryder Scott Company.
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_______________________
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| | * Filed herewith.
† Identifies management contracts and compensatory plans or arrangements.
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