Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in the statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:

• resolution of pending and future rate cases and negotiations, including various performance-based rate discussions, and other regulatory decisions, including those related to Entergy's System Agreement and utility supply plan
• Entergy's ability to reduce its operation and maintenance costs, particularly at its Non-Utility Nuclear generating facilities, including the uncertainty of negotiations with unions to agree to such reductions
• the performance of Entergy's generating plants, and particularly the capacity factors at its nuclear generating facilities
• prices for power generated by Entergy's unregulated generating facilities, the ability to extend or replace the existing purchased power agreements for those facilities, including the Non-Utility Nuclear plants, and the prices and availability of power Entergy must purchase for its utility customers
• Entergy's ability to develop and execute on a point of view regarding prices of electricity, natural gas, and other energy-related commodities
• Entergy-Koch's profitability in trading physical and financial natural gas and power as well as other energy-related contracts
• changes in the number of participants in the energy trading market, and in their creditworthiness and risk profile
• changes in the financial markets, particularly those affecting the availability of capital and Entergy's ability to refinance existing debt and to fund investments and acquisitions
• actions of rating agencies, including changes in the ratings of debt and preferred stock
• changes in inflation and interest rates
• Entergy's ability to purchase and sell assets at attractive prices and on other attractive terms
• changes in ownership of joint ventures
• volatility and changes in markets for electricity, natural gas, uranium, and other energy-related commodities
• changes in utility regulation, including the beginning or end of retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, and the establishment of a regional transmission organization that includes Entergy's utility service territory
• changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of Indian Point or other nuclear generating facilities
• resolution of pending or future applications for license extensions of nuclear generating facilities
• changes in law resulting from proposed energy legislation
• changes in environmental, tax, and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, mercury, and other substances
• the economic climate, and particularly growth in Entergy's service territory
• variations in weather, hurricanes, and other disasters
• advances in technology
• the potential impacts of threatened or actual terrorism and war
• the success of Entergy's strategies to reduce current tax payments
• the effects of litigation and government investigations
• changes in accounting standards, corporate governance, and securities law requirements
• Entergy's ability to attract and retain talented management and directors.

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Certain abbreviations or acronyms used in the text are defined below:

DEFINITIONS (Continued)

DEFINITIONS (Concluded)

Entergy's consolidated earnings applicable to common stock for the first quarter 2004 and 2003 were as follows:

Entergy's income before taxes is discussed below according to the operating segments listed above. Earnings for 2003 include the $142.9 million net-of-tax cumulative effect of changes in accounting principle that increased earnings in the first quarter of 2003, almost entirely resulting from the implementation of SFAS 143. See Note 9 to the consolidated financial statements in the Form 10-K for further discussion of the implementation of SFAS 143. See Note 7 to the consolidated financial statements for more information concerning Entergy's operating segments and their financial results for the first quarter of 2004 and 2003.

Refer to SELECTED OPERATING RESULTS OF ENTERGY CORPORATION AND SUBSIDIARIES for further information with respect to operating statistics.

The increase in earnings for the U.S. Utility for the first quarter of 2004 compared to the first quarter of 2003 from $107.8 million to $115.7 million was primarily due to the $21.3 million net-of-tax cumulative effect of a change in accounting principle that reduced earnings at Entergy Gulf States in the first quarter of 2003 upon implementation of SFAS 143. Income before the cumulative effect of accounting change decreased by $13.4 million in 2004 compared to 2003 primarily due to a decrease in net revenue, partially offset by a decrease in interest charges.

Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing the first quarter of 2004 to the first quarter of 2003.

The volume/weather variance resulted from increased usage in the service territories. Billed usage increased a total of 199 GWh in the industrial, commercial, and governmental sectors. The increase, however, was partially offset by a decrease of 117 GWh in the residential sector primarily due to colder than normal weather in the first quarter of 2003.

Base rates increased net revenue due to a base rate increase at Entergy New Orleans that became effective in June 2003.

The deferred fuel cost revision variance primarily resulted from a revised unbilled sales pricing estimate made in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs at Entergy Louisiana. Deferred fuel cost revisions also decreased net revenue due to a revised estimate of fuel costs filed for recovery at Entergy Arkansas in the March 2004 energy cost recovery rider.

The price applied to unbilled sales variance resulted from a decrease in price in the first quarter of 2004 caused primarily by the effect of nuclear plant outages in 2003 on average fuel costs.

Gross operating revenues, fuel and purchased power expenses, and regulatory charges (credits)

Gross operating revenues include an increase in fuel cost recovery revenues of $138.5 million primarily due to higher fuel rates in the first quarter of 2004 resulting from increases in the market prices of non-associated purchased power and natural gas and collections of previous deferrals of fuel costs. As such, this revenue increase is offset by increased fuel and purchased power expenses.

Other regulatory charges decreased primarily due to the cessation of the Grand Gulf Accelerated Recovery Tariff that was suspended in July 2003 in addition to the amortization of deferred capacity charges for summer 2001 power purchases at Entergy Gulf States and Entergy Louisiana.

Interest and other charges decreased primarily due to a decrease in interest on long-term debt as a result of the net retirement and refinancing of long-term debt in 2003. See Note 5 to the consolidated financial statements in the Form 10-K for detail of long-term debt.

Following are key performance measures for Non-Utility Nuclear for the first quarters of 2004 and 2003:

The decrease in earnings for Non-Utility Nuclear for the first quarter of 2004 compared to the first quarter of 2003 from $197.0 million to $68.8 million was due to the $160.3 million net-of-tax cumulative effect of a change in accounting principle recognized in the first quarter of 2003 upon implementation of SFAS 143. See Note 9 to the consolidated financial statements in the Form 10-K for further discussion of the implementation of SFAS 143. Income before the cumulative effect of accounting change increased by $32.1 million. The increase was due to higher revenues, which increased by $35 million, resulting from increased generation in 2004 due to fewer unplanned outages in 2004 and power uprates completed in 2003, and higher contract pricing. Lower operation and maintenance expenses, which decreased by $23 million, also contributed to the increase in income.

The decrease in earnings for Energy Commodity Services from $93.8 million for the first quarter 2003 to $9.8 million for the first quarter 2004 was primarily due to lower earnings from Entergy's investment in Entergy-Koch. The income from Entergy's investment in Entergy-Koch was lower by $77 million in 2004 primarily as a result of:

• The loss of disproportionate income sharing, which accounted for $39 million of first quarter 2003 earnings and is discussed in the paragraph below.
• Lower earnings at Entergy-Koch Trading (EKT), resulting from reduced volatility, which also resulted in lower point-of-view trading profits.

Earnings for Gulf South Pipeline were basically flat as compared to first quarter 2003, as revenues from higher throughput and contract prices were offset by the loss of disproportionate income sharing and by higher costs resulting from legal expenses and remediation costs incurred in connection with a casing leak that occurred in late 2003 at the Magnolia storage facility.

Following are key performance measures for Entergy-Koch's operations for the first quarters of 2004 and 2003:

See "Management's Financial Discussion and Analysis - Liquidity and Capital Resources" in the Form 10-K for a discussion of Entergy's capital structure, capital expenditure plans and other uses of capital, and sources of capital.

As discussed in the Form 10-K, Entergy Corporation, Entergy Louisiana, and Entergy Mississippi each has a 364-day credit facility due to expire in May 2004, which each of them expects to renew prior to expiration. Entergy Corporation has bank commitments for participation in its facility sufficient to renew it for its current amount of $1.45 billion, with approximately two-thirds of the committed amount for a term of three years and the remainder for a 364-day term. Entergy Arkansas has a 364-day credit facility that it renewed in 2004, increasing the amount to $85 million, that is now due to expire in April 2005. As of March 31, 2004, no borrowings were outstanding on the credit facilities. See Note 4 to the consolidated financial statements for additional discussion of Entergy's short-term credit facilities.

As shown in Entergy's Statements of Cash Flows, cash flows for the three months ended March 31, 2004 and 2003 were as follows:

Entergy's cash flow provided by operating activities increased by $348 million in the first quarter of 2004 compared to the first quarter of 2003 primarily due to the following:

• The U.S. Utility provided $301 million in operating cash flow, compared to providing $99 million in the first quarter of 2003. The increase resulted primarily from improved recovery of fuel costs compared to first quarter 2003.
• The Non-Utility Nuclear business provided $129 million in operating cash flow, compared to providing $50 million in the first quarter of 2003. The increase resulted primarily from an increase in generation that led to an increase in revenues and lower refueling outage cash costs.
• Energy Commodity Services used $10 million in operating cash flow compared to using $56 million in the first quarter of 2003. The decrease in cash used resulted primarily from a one-time $33 million payment in 2003 related to a generation contract in the non-nuclear wholesale assets business.

Net cash used in investing activities decreased by $355 million in the first quarter of 2004 compared to the first quarter of 2003 primarily due to the following:

• System Energy had three-year letters of credit in place that were scheduled to expire in March 2003 securing certain of its obligations related to the sale-leaseback of a portion of Grand Gulf 1. System Energy replaced the letters of credit with new three-year letters of credit totaling approximately $198 million that were backed by cash collateral. System Energy used approximately $193 million in March 2003 to provide this cash collateral. (In December 2003, System Energy replaced the cash-backed letters of credit with syndicated bank letters of credit that expire in May 2007.)
• Temporary investments of $50 million with initial maturities of greater than 90 days matured in the first quarter of 2004.
• The Non-Utility Nuclear segment purchased $53 million more nuclear fuel in 2003 than in the first quarter 2004 to provide for refueling outages.

Financing activities provided $41 million in the first quarter of 2004 compared to using $398 million in the first quarter of 2003 primarily due to the following:

• Issuances of long-term debt net of retirements by the U.S. Utility segment provided $78 million in the first quarter 2004 and retirements of long-term debt net of issuances used $519 million in the first quarter 2003. See Note 4 to the consolidated financial statements for the details of the long-term debt activity in the first quarter of 2004.
• The non-nuclear wholesale asset business retired the $79 million Top of Iowa wind project debt at its maturity in January 2003.
• Entergy Corporation issued $158 million of long-term notes in March 2003; and
• Entergy Corporation repurchased $28 million of its common stock in the first quarter 2004. As discussed in the Form 10-K, in accordance with Entergy's stock option plans, Entergy periodically grants stock options to its employees, which may be exercised to obtain shares of Entergy's common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy's management has been authorized to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. Entergy Corporation repurchased 484,000 shares of its common stock in the first quarter 2004.

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Significant Factors and Known Trends" in the Form 10-K for discussions of rate regulation and fuel-cost recovery, market and credit risks, utility restructuring, and nuclear matters. Following are updates to the information provided in the Form 10-K.

Rate Regulation and Fuel-Cost Recovery

See the Form 10-K for the chart summarizing material rate proceedings.  Following are updates to that chart.  Regarding base rates in Entergy Gulf States' Texas jurisdiction, those rates are currently set at rates approved by the PUCT in June 1999.  Depending on the start date for retail open access in Entergy Gulf States' Texas service territory, base rates may remain unchanged until the implementation of retail open access.  Regarding Entergy Mississippi, it made its formula rate plan filing with the MPSC in March 2004 based on a 2003 test year.  In April 2004, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based on an adjusted return on common equity midpoint of 10.77%, establishing an allowed regulatory earnings range of 9.3% to 12.2%.

System Agreement Litigation

See the Form 10-K for a discussion of the proceeding commenced at FERC by the LPSC regarding production cost equalization under the System Agreement, the ALJ Initial Decision in the proceeding, and the "Order of Investigation" issued by the APSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include that: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; implementation of resource planning for the Entergy System will be impeded; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in s ubstantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the costs of the Vidalia project should be included in Entergy Louisiana's relative production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method.

As reported in the Form 10-K, if FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in production costs allocated to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in production costs allocated to companies whose costs currently are projected to exceed that average. Management believes that any changes in the allocation of production costs resulting from a FERC decision should result in similar rate changes for retail customers. Therefore, management does not believe that this proceeding will have a material effect on the financial condition of any of the domestic utility companies, although the outcome of the proceeding at FERC cannot be predicted at this time.

Entergy Arkansas also filed its initial testimony in response to the APSC's February Order of Investigation discussed in the Form 10-K. The testimony emphasizes that the ALJ Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; and states that Entergy Arkansas believes that it is premature, before FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.

In addition, as discussed in the Form 10-K, the APSC had publicly announced its intention to initiate an inquiry into Entergy Louisiana's Vidalia purchased power contract. In April 2004, the APSC commenced the investigation, and has requested historical documents, records, and information from Entergy Arkansas. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Procedural schedules have not been established yet in these investigations. Also in April, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the Sys tem Agreement for one or more of the domestic utility companies. In addition, the LPSC staff has proposed that a pending LPSC proceeding investigating the System Agreement should now include certain additional issues that are pending before the FERC at this time.

Power Generation

As discussed more fully in the Form 10-K, the sale of electricity from the power generation plants owned by Entergy's Non-Utility Nuclear business and Energy Commodity Services, unless otherwise contracted, is subject to the fluctuation of market power prices. Following is an updated summary of the amount of Non-Utility Nuclear's output that is sold forward as of April 30, 2004 under physical or financial contracts at fixed prices (2004 represents the remainder of the year):

In addition to selling the power produced by its plants, the Non-Utility Nuclear business sells installed capacity to load-serving distribution companies in order for those companies to meet requirements placed on them by the Independent System Operators in their area. Following is an updated summary of the amount of the Non-Utility Nuclear business' installed capacity that is sold forward, and the blended amount of the Non-Utility Nuclear business' planned generation output and installed capacity that is currently sold forward, as of April 30, 2004:

Transmission

Entergy also proposes to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC and any party contesting such determination, including Entergy, would be required to seek review at the FERC.

Entergy has requested that the FERC provide its retail regulators sufficient time to review the proposal and provide their comments prior to the FERC ruling on the proposal. In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC has sought comments from all interested parties on this issue, with initial comments due May 17, 2004 and reply comments due in June 2004. As discussed in "Retail-Texas," a proceeding is pending currently before the PUCT in which it is evaluating whether the Entergy transmission organization, with oversight, is sufficiently independent to facilitate retail open access in Texas. A hearing in that proceeding is currently scheduled in June 2004. The processes for obtaining comments from the other retail regulators on Entergy's transmission proposal have not yet been established.

FERC's Supply Margin Assessment

In November 2001, FERC issued an order that established a new generation market power screen (called Supply Margin Assessment) for purposes of evaluating a utility's request for market-based rate authority, applied that new screen to the Entergy System (among others), determined that Entergy and the others failed the screen within their respective control areas, and ordered these utilities to implement certain mitigation measures as a condition to their continued ability to buy and sell at market-based rates. Among other things, the mitigation measures would require that Entergy transact at cost-based rates when it sells in the hourly wholesale market within its control area. Entergy requested rehearing of the order, and FERC delayed the implementation of certain mitigation measures until such time as it had the opportunity to consider the rehearing request. In June 2003, the FERC proposed and ultimately adopted new market behavior rules and tariff provisions that would be applied to any market-based sale. Entergy modified its market-based rate tariffs to reflect the new provisions but requested rehearing of FERC's order.

In April 2004, the FERC issued its Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy. In its Order on Rehearing, the FERC established a new interim generation market power analysis that will consider two indicative market power screens: (1) the uncommitted pivotal supplier screen that is designed to measure an applicant's market power based on the control area market's annual peak demand; and (2) the uncommitted market share screen that is designed to evaluate an applicant's market share of uncommitted capacity on a seasonal basis. An integrated utility's native load obligation will be reflected in both screens, however, the proxy for native load obligation differs between the screens. For the uncommitted pivotal supplier screen the proxy for native load is the average of the daily native load peaks during the month in which the annual peak load day occurs; for the uncommitted market share screen the proxy for native load is the minimum pea k load day for each season. In the event an applicant fails either of these screens, there will be a rebuttable presumption that market power exists. The applicant will then have the opportunity to either: (1) submit a more detailed market power analysis that reflects market prices and measures an applicant's "economic capacity" and "available economic capacity;" or (2) propose case-specific mitigation tailored to the applicant's specific circumstances or adopt cost-based rates for sales within the applicant's control area. In its Order on Rehearing, the FERC also determined: (1) that transmission market power and the need to employ an independent entity to operate and administer an applicant's OASIS site is more properly considered in other proceedings, to the extent appropriate, and would not be considered in evaluating an applicant's generation market power for purposes of granting market-based rate authority; and (2) to eliminate the exemption from the generation market power analysis for sales within an RTO/ISO that had approved market monitoring. Entergy must re-file its generation market analyses using the two indicative screens within 60 days of the issuance of the Order on Rehearing.

In a companion order, issued on the same day, the FERC initiated a rulemaking proceeding to address, among other things, whether the FERC should retain or modify its existing four-prong test for evaluating market-based rate applications (i.e., whether the applicant has generation or transmission market power, whether the applicant can erect barriers to entry, and whether there are affiliate abuse or reciprocal dealing concerns), and whether the FERC should adopt different approaches for affiliate transactions. Initially, the FERC will hold a series of technical conferences to determine the issues that need to be considered and the procedural direction the rulemaking should take. The first of these technical conferences is scheduled in June 2004.

Interconnection Orders

See the Form 10-K for discussion of the order on rehearing issued by FERC on March 5, 2004 that modified Order 2003 to, among other things, eliminate the requirement that the generation owners receive their money back in no more than five years and to include a requirement that the generation owners receive credits only when transmission service is taken from the specific generating facility served by the interconnection or upgrade. In addition, the order on rehearing clarified that a transmission provider continues to have the option to charge a transmission rate that is the higher of the incremental cost rate for network upgrades required to interconnect a generating facility or an embedded cost rate so as to ensure that "other transmission customers, including a Transmission Provider's native load, will not subsidize Network Upgrades required to interconnect merchant generation." Consistent with the principles articulated in the order on rehearing, Entergy incorporated into its recent ICT filing an approach to the pricing of transmission expansion that protects the transmission provider's native load customers from the effects of service requests by other transmission customers and provides more efficient price signals for resource procurement and siting decisions. In addition, the transmission expansion pricing protocol included in the ICT filing proposes that the ICT review all costs that were previously charged to interconnecting customers for interconnection facilities to determine whether, under the proposed pricing policy, such costs were properly classified as Supplemental Upgrades that are directly assigned to the interconnecting generator or whether such costs were properly Base Plan Upgrades that are rolled into transmission rates for all customers. Any payments made by an interconnecting generator that have not already been refunded to that customer through crediting for transmission service will be subject to the cost assignment by the ICT.

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of the status of retail open access in Entergy Gulf States' Texas service territory and Entergy Gulf States' independent organization request. On March 15, 2004, the PUCT issued a preliminary order in Entergy Gulf States' independence proceeding in which the PUCT decided two key issues related to the proceeding and concluded that the December 2004 target date for the initiation of retail open access in Entergy Gulf States' Texas service territory is not feasible, but specifically declined to set a new target date at least until the market readiness proceeding was underway. The preliminary order addressed the following key issues: (1) whether the PUCT should delay further efforts to implement retail open access in Entergy Gulf States' Texas service territory until the establishment of a FERC-approved RTO, in view of the suspension of efforts to develop the SeTrans RTO; and (2) what cr iteria should be used to certify an independent organization for Entergy Gulf States' Texas service territory.

The PUCT found that it is not necessary to delay further efforts to establish retail competition in Entergy Gulf States' Texas service territory until after a FERC-approved RTO can serve as the independent organization for that region. The PUCT also determined that the ultimate question in the proceeding is whether Entergy Gulf States' proposed independent organization, Entergy Transmission Organization, is sufficiently independent of any producer or seller of electricity that its decisions will not be unduly influenced by any producer or seller. The PUCT identified the criteria that are to be considered in answering this ultimate question that includes (1) whether the independent organization's decisions are controlled or dominated by any market participant or market segment; and (2) whether the independent organization has day-to-day operational control over the facilities involved. In determining whether the Entergy Transmission Organization should be certified as independent, the PU CT further stated that the issues to be addressed were whether the proposed structure would ensure that the affiliate was independent, and if not, what additional safeguards should be imposed to assure independence. The PUCT also limited any finding of independence in this docket to be applicable to the pilot only and indicated that should it be necessary, the PUCT would review the issue of independence in the market readiness proceeding as well. The preliminary order also states that other issues to be addressed in this proceeding include (1) the costs of implementing Entergy Gulf States' proposal; (2) what changes or additions, if any, may be necessary to the approved protocols or other public documents; and (3) the date by which the pilot project under the protocols can begin. Hearings are scheduled for June 2004.

The preliminary order further directed the parties to the independence proceeding not to address the issue of when full retail competition should start in Entergy Gulf States' Texas service territory.

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates" in the Form 10-K for a discussion of the estimates and judgments necessary in Entergy's accounting for nuclear decommissioning costs, impairment of long-lived assets, mark-to-market derivative instruments, pension and other postretirement costs, and other contingencies.