ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
Dec. 31, 2016
Accounting Policies [Abstract]
Basis of Presentation and Reorganization	Basis of Presentation: The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Offshore, Stone Energy Holding, L.L.C. and Stone Energy Canada, ULC. On August 29, 2016 our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore. On December 2, 2016, Stone Energy Canada, ULC was dissolved. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation. On May 27, 2016, the board of directors of the Company approved a 1-for-10 reverse stock split of the Company's issued and outstanding shares of common stock. The reverse stock split was effective upon the filing and effectiveness of a certificate of amendment to the Company's certificate of incorporation after the market closed on June 10, 2016, and the common stock began trading on a split-adjusted basis when the market opened on June 13, 2016. The effect of the reverse stock split was to combine each 10 shares of outstanding common stock prior to the reverse split into one new share subsequent to the reverse split. The Company's authorized shares of common stock were proportionately decreased in connection with the reverse stock split. Additionally, the overall and per share limitations in the Company’s 2009 Amended and Restated Stock Incentive Plan, as amended from time to time, and outstanding awards thereunder were also proportionately adjusted. The Company retained the current par value of $.01 per share for all shares of common stock. All references in the financial statements and notes thereto to number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the 1-for-10 reverse stock split. Stockholders' equity reflects the reverse stock split by reclassifying from common stock to additional paid-in capital an amount equal to the par value of the reduction in the number of shares as a result of the reverse split. Reorganization: We have applied Accounting Standards Codification ("ASC") 852, "Reorganizations", in preparing the consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees and other expenses incurred in the Chapter 11 cases, and unamortized deferred financing costs, premiums and discounts associated with debt classified as liabilities subject to compromise, have been recorded as reorganization items on the consolidated statement of operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the consolidated balance sheet at December 31, 2016 as liabilities subject to compromise. These liabilities are reported at the amounts the Company expects will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. See Note 2 – Chapter 11 Proceedings for more information regarding reorganization items and liabilities subject to compromise. The Chapter 11 proceedings do not include our former foreign subsidiary Stone Energy Canada, ULC.
Use of Estimates	Use of Estimates: The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles ("GAAP") 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 ("DD&A") expense, unevaluated property costs, estimated future net cash flows from proved reserves, costs to abandon oil and gas properties, income taxes, liabilities subject to compromise versus not subject to compromise, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, effectiveness and estimated fair value of derivative contracts, estimates of fair value in business combinations and contingencies.
Fair Value Measurements	Fair Value Measurements: U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of December 31, 2016 and 2015, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. U.S. GAAP establishes a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions. As of December 31, 2016 and 2015, we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts were the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, see Note 7 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.
Hybrid Debt Instruments	Hybrid Debt Instruments: In 2012, we issued $300,000 in aggregate principal amount of 1 3⁄4% Senior Convertible Notes due 2017 (the "2017 Convertible Notes"). See Note 11 – Debt. On that same day we entered into convertible note hedging transactions which were expected to reduce the potential dilution to our common shareholders upon conversion of the notes. In accordance with ASC 480-20 and ASC 470, we accounted for the debt and equity portions of the notes in a manner that reflects our nonconvertible borrowing rate when interest is recognized in subsequent periods. This results in the separation of the debt component, classification of the remaining component in stockholders’ equity, and accretion of the resulting discount as interest expense. Additionally, the hedging transactions met the criteria for classification as equity transactions and were recorded as such. The convertible note hedging transactions have since been terminated in connection with our Chapter 11 proceedings.
Cash and Cash Equivalents	Cash and Cash Equivalents: We consider all money market funds and 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	Oil and Gas Properties: We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment 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 are 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. We capitalize a portion of the interest costs incurred on our debt based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase levels of production from an existing completion interval are charged to lease operating expense in the period incurred. U.S. GAAP allows the option of two acceptable methods for accounting for oil and gas properties. The successful efforts method is the allowable alternative to the full cost method. The primary differences between the two methods are in the treatment of exploration costs, the computation of DD&A expense and the assessment of impairment of oil and gas properties. Under the full cost method, all exploratory costs are capitalized, while under the successful efforts method, exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under the full cost method, DD&A expense is computed on cost centers represented by entire countries, while under the successful efforts method, cost centers are represented by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs. Under the full cost method, oil and gas properties are subject to the ceiling test as discussed below while under the successful efforts method oil and gas properties are assessed for impairment in accordance with ASC 360. We amortize our investment in oil and gas properties through DD&A expense using the units of production (the "UOP") method. Under the UOP method, the quarterly provision for DD&A expense is computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of period reserves being determined by adding production to the end of period reserves), and applying the respective rate to the net cost of proved oil and gas properties, including future development costs. Under the full cost method, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. 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. Sales of oil and gas properties are accounted for as adjustments to net oil and gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Our estimated net proved oil and natural gas reserves at December 31, 2016 have been prepared 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.
Asset Retirement Obligations	Asset Retirement Obligations: U.S. GAAP 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 removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The application of this rule requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital. U.S. GAAP requires that our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.
Other Property and Equipment	Other Property and Equipment: Our office buildings in Lafayette, Louisiana are being depreciated on the straight-line method over their estimated useful lives of 39 years.
Earnings Per Common Share	Earnings Per Common Share: Under U.S. GAAP, certain instruments granted in share-based payment transactions are considered participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method. Companies are required to treat unvested share-based payment awards with a right to receive non-forfeitable dividends as a separate class of securities in calculating earnings per share.
Production Revenue	Production Revenue: We recognize production revenue under the entitlements method of accounting. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for undelivered or underdelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production.
Income Taxes	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 and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects, including future abandonment costs, are capitalized and amortized using the UOP method. For income tax purposes, only the leasehold, geological and geophysical and equipment relative to successful wells are capitalized and recovered through DD&A, although for 2014, 2015 and 2016, special provisions allowed for current deductions for the cost of certain equipment. 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, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and different reporting methods for employee compensation.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities: The nature of a derivative instrument must be evaluated to determine if it qualifies as a hedging instrument. If the instrument qualifies as a hedging instrument, it is recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and natural gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value and subsequent changes in fair value are recognized in earnings through derivative expense (income). Monthly settlements of ineffective hedges and derivative instruments not qualifying as hedging instruments are recognized in earnings through derivative expense (income) and cash flows from operating activities. Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. These derivatives are generally designated as cash flow hedges upon entering into the contracts. We do not enter into derivative transactions for trading purposes. We have no fair value hedges. During 2016, 2015 and 2014, a portion of our oil and natural gas production was hedged with fixed-price swaps and collars with various counterparties. We did not have any outstanding derivative contracts at December 31, 2016. In January and February 2017, we entered into various fixed-price swaps and put contracts for a portion of our expected 2017 and 2018 oil production from the Gulf Coast Basin. As of February 23, 2017, our outstanding fixed-price swaps and put contracts are with Natixis, Bank of America Merrill Lynch, The Toronto-Dominion Bank and The Bank of Nova Scotia. Our fixed-price oil swap settlements are based on an average of the New York Mercantile Exchange ("NYMEX") closing price for West Texas Intermediate ("WTI") crude oil during the entire calendar month. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. 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 contract represents our maximum cash exposure. We are not obligated to make any further payments under the put contract regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if the NYMEX prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above the floor. Our put contract settlements are based on the average of the NYMEX closing price for WTI crude oil during the entire calendar month.
Share-Based Compensation	Share-Based Compensation: We record share-based compensation using the grant date fair value of issued stock options, stock awards and restricted stock over the vesting period of the instrument. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The fair value of stock awards and restricted stock is typically determined based on the average of our high and low stock prices on the grant date.
Recently Issued Accounting Standards	Recently Issued Accounting Standards: In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU 2014-09, "Revenue from Contracts with Customers" to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 15, 2017. We expect to apply the modified retrospective approach upon adoption of this standard. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect. In August 2014, the FASB issued ASU 2014-15, "Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40)". The guidance requires management to evaluate whether there are conditions and events that raise substantial doubt about the company's ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Additionally, management is required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it concludes its plans alleviate substantial doubt about the company's ability to continue as a going concern. ASU 2014-15 became effective for us on December 15, 2016. The standard impacted our disclosures but had no effect on our financial position, results of operations or cash flows. In November 2015, the FASB issued ASU 2015-17, "Balance Sheet Classification of Deferred Taxes" to simplify the presentation of deferred income taxes. The guidance allows for the presentation of all deferred tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent on the balance sheet. We early adopted ASU 2015-17, on a retrospective basis, which affected our disclosures of deferred tax assets and liabilities as of December 31, 2016 and 2015, but had no effect on our financial position, results of operations or cash flows. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements. In March 2016, the FASB issued ASU 2016-09, "Compensation – Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2016

Basis of Presentation and Reorganization

Basis of Presentation:

The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Offshore, Stone Energy Holding, L.L.C. and Stone Energy Canada, ULC. On August 29, 2016 our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore. On December 2, 2016, Stone Energy Canada, ULC was dissolved. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation.

On May 27, 2016, the board of directors of the Company approved a 1-for-10 reverse stock split of the Company's issued and outstanding shares of common stock. The reverse stock split was effective upon the filing and effectiveness of a certificate of amendment to the Company's certificate of incorporation after the market closed on June 10, 2016, and the common stock began trading on a split-adjusted basis when the market opened on June 13, 2016. The effect of the reverse stock split was to combine each 10 shares of outstanding common stock prior to the reverse split into one new share subsequent to the reverse split. The Company's authorized shares of common stock were proportionately decreased in connection with the reverse stock split. Additionally, the overall and per share limitations in the Company’s 2009 Amended and Restated Stock Incentive Plan, as amended from time to time, and outstanding awards thereunder were also proportionately adjusted. The Company retained the current par value of $.01 per share for all shares of common stock.

All references in the financial statements and notes thereto to number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the 1-for-10 reverse stock split. Stockholders' equity reflects the reverse stock split by reclassifying from common stock to additional paid-in capital an amount equal to the par value of the reduction in the number of shares as a result of the reverse split.

Reorganization:

We have applied Accounting Standards Codification ("ASC") 852, "Reorganizations", in preparing the consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees and other expenses incurred in the Chapter 11 cases, and unamortized deferred financing costs, premiums and discounts associated with debt classified as liabilities subject to compromise, have been recorded as reorganization items on the consolidated statement of operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the consolidated balance sheet at December 31, 2016 as liabilities subject to compromise. These liabilities are reported at the amounts the Company expects will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. See Note 2 – Chapter 11 Proceedings for more information regarding reorganization items and liabilities subject to compromise.

The Chapter 11 proceedings do not include our former foreign subsidiary Stone Energy Canada, ULC.

Use of Estimates

Use of Estimates:

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles ("GAAP") 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 ("DD&A") expense, unevaluated property costs, estimated future net cash flows from proved reserves, costs to abandon oil and gas properties, income taxes, liabilities subject to compromise versus not subject to compromise, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, effectiveness and estimated fair value of derivative contracts, estimates of fair value in business combinations and contingencies.

Fair Value Measurements

Fair Value Measurements:

U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of December 31, 2016 and 2015, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities.

U.S. GAAP establishes a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

As of December 31, 2016 and 2015, we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts were the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, see Note 7 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.

Hybrid Debt Instruments

Hybrid Debt Instruments:

In 2012, we issued $300,000 in aggregate principal amount of 1 3⁄4% Senior Convertible Notes due 2017 (the "2017 Convertible Notes"). See Note 11 – Debt. On that same day we entered into convertible note hedging transactions which were expected to reduce the potential dilution to our common shareholders upon conversion of the notes. In accordance with ASC 480-20 and ASC 470, we accounted for the debt and equity portions of the notes in a manner that reflects our nonconvertible borrowing rate when interest is recognized in subsequent periods. This results in the separation of the debt component, classification of the remaining component in stockholders’ equity, and accretion of the resulting discount as interest expense. Additionally, the hedging transactions met the criteria for classification as equity transactions and were recorded as such. The convertible note hedging transactions have since been terminated in connection with our Chapter 11 proceedings.

Cash and Cash Equivalents

Cash and Cash Equivalents:

We consider all money market funds and 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

Oil and Gas Properties:

We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment 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 are 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. We capitalize a portion of the interest costs incurred on our debt based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase levels of production from an existing completion interval are charged to lease operating expense in the period incurred.

U.S. GAAP allows the option of two acceptable methods for accounting for oil and gas properties. The successful efforts method is the allowable alternative to the full cost method. The primary differences between the two methods are in the treatment of exploration costs, the computation of DD&A expense and the assessment of impairment of oil and gas properties. Under the full cost method, all exploratory costs are capitalized, while under the successful efforts method, exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under the full cost method, DD&A expense is computed on cost centers represented by entire countries, while under the successful efforts method, cost centers are represented by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs. Under the full cost method, oil and gas properties are subject to the ceiling test as discussed below while under the successful efforts method oil and gas properties are assessed for impairment in accordance with ASC 360.

We amortize our investment in oil and gas properties through DD&A expense using the units of production (the "UOP") method. Under the UOP method, the quarterly provision for DD&A expense is computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of period reserves being determined by adding production to the end of period reserves), and applying the respective rate to the net cost of proved oil and gas properties, including future development costs.

Under the full cost method, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. 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.

Sales of oil and gas properties are accounted for as adjustments to net oil and gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Our estimated net proved oil and natural gas reserves at December 31, 2016 have been prepared 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.

Asset Retirement Obligations

Asset Retirement Obligations:

U.S. GAAP 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 removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The application of this rule requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital. U.S. GAAP requires that our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

Other Property and Equipment

Other Property and Equipment:

Our office buildings in Lafayette, Louisiana are being depreciated on the straight-line method over their estimated useful lives of 39 years.

Earnings Per Common Share

Earnings Per Common Share:

Under U.S. GAAP, certain instruments granted in share-based payment transactions are considered participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method. Companies are required to treat unvested share-based payment awards with a right to receive non-forfeitable dividends as a separate class of securities in calculating earnings per share.

Production Revenue

Production Revenue:

We recognize production revenue under the entitlements method of accounting. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for undelivered or underdelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production.

Income Taxes

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 and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects, including future abandonment costs, are capitalized and amortized using the UOP method. For income tax purposes, only the leasehold, geological and geophysical and equipment relative to successful wells are capitalized and recovered through DD&A, although for 2014, 2015 and 2016, special provisions allowed for current deductions for the cost of certain equipment. 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, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and different reporting methods for employee compensation.

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities:

The nature of a derivative instrument must be evaluated to determine if it qualifies as a hedging instrument. If the instrument qualifies as a hedging instrument, it is recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and natural gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value and subsequent changes in fair value are recognized in earnings through derivative expense (income). Monthly settlements of ineffective hedges and derivative instruments not qualifying as hedging instruments are recognized in earnings through derivative expense (income) and cash flows from operating activities.

Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. These derivatives are generally designated as cash flow hedges upon entering into the contracts. We do not enter into derivative transactions for trading purposes. We have no fair value hedges.

During 2016, 2015 and 2014, a portion of our oil and natural gas production was hedged with fixed-price swaps and collars with various counterparties. We did not have any outstanding derivative contracts at December 31, 2016. In January and February 2017, we entered into various fixed-price swaps and put contracts for a portion of our expected 2017 and 2018 oil production from the Gulf Coast Basin. As of February 23, 2017, our outstanding fixed-price swaps and put contracts are with Natixis, Bank of America Merrill Lynch, The Toronto-Dominion Bank and The Bank of Nova Scotia.

Our fixed-price oil swap settlements are based on an average of the New York Mercantile Exchange ("NYMEX") closing price for West Texas Intermediate ("WTI") crude oil during the entire calendar month. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. 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 contract represents our maximum cash exposure. We are not obligated to make any further payments under the put contract regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if the NYMEX prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above the floor. Our put contract settlements are based on the average of the NYMEX closing price for WTI crude oil during the entire calendar month.

Share-Based Compensation

Share-Based Compensation:

We record share-based compensation using the grant date fair value of issued stock options, stock awards and restricted stock over the vesting period of the instrument. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The fair value of stock awards and restricted stock is typically determined based on the average of our high and low stock prices on the grant date.

Recently Issued Accounting Standards

Recently Issued Accounting Standards:

In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU 2014-09, "Revenue from Contracts with Customers" to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 15, 2017. We expect to apply the modified retrospective approach upon adoption of this standard. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

In August 2014, the FASB issued ASU 2014-15, "Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40)". The guidance requires management to evaluate whether there are conditions and events that raise substantial doubt about the company's ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Additionally, management is required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it concludes its plans alleviate substantial doubt about the company's ability to continue as a going concern. ASU 2014-15 became effective for us on December 15, 2016. The standard impacted our disclosures but had no effect on our financial position, results of operations or cash flows.

In November 2015, the FASB issued ASU 2015-17, "Balance Sheet Classification of Deferred Taxes" to simplify the presentation of deferred income taxes. The guidance allows for the presentation of all deferred tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent on the balance sheet. We early adopted ASU 2015-17, on a retrospective basis, which affected our disclosures of deferred tax assets and liabilities as of December 31, 2016 and 2015, but had no effect on our financial position, results of operations or cash flows.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements.

In March 2016, the FASB issued ASU 2016-09, "Compensation – Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.