System Energy Resources, Inc.  Management's Financial Discussion and Analysis 269 Operating Activities Cash flow from operations increased by $232.1 million in 2004 primarily due to income tax refunds of $70.6 million in 2004 compared to income tax payments of $230.9 million in 2003.
The increase was partially offset by money pool activity, as discussed below.
In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold.
The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations.
The cumulative adjustment placing these companies on the new methodology resulted in a $430 million deduction for System Energy on Entergy's 2003 income tax return.
There was no cash benefit from the method change in 2003.
In 2004 System Energy realized $144 million in cash tax benefit from the method change.
This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit.
Cash flow from operations decreased by $124.8 million in 2003 primarily due to the following: ?
an increase in federal income taxes paid of $74.0 million in 2003 compared to 2002; ?
the cessation of the Entergy Mississippi GGART.
System Energy collected $21.7 million in 2003 and $40.8 million in 2002 from Entergy Mississippi in conjunction with the GGART, which provided for the acceleration of Entergy Mississippi's Grand Gulf purchased power obligation.
The MPSC authorized cessation of the GGART effective July 1, 2003.
See Note 2 to the domestic utility companies and System Energy financial statements for further discussion of the GGART; and ?
money pool activity, as discussed below.
System Energy's receivables from the money pool were as follows as of December 31 for each of the following years:
## Table 0 ##
Money pool activity used $42.5 million of System Energy's operating cash flows in 2004, used $12.0 million in 2003, and provided $6.8 million in 2002.
See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Investing Activities Net cash used for investing activities was practically unchanged in 2004 compared to 2003 primarily because an increase in construction expenditures caused by a reclassification of inventory items to capital was significantly offset by the maturity of $6.5 million of other temporary investments that had been made in 2003, which provided cash in 2004.
The increase of $16.2 million in net cash used in investing activities in 2003 was primarily due to the following: ?
the maturity in 2002 of $22.4 million of other temporary investments that had been made in 2001, which provided cash in 2002; ?
an increase in decommissioning trust contributions and realized change in trust assets of $8.2 million in 2003 compared to 2002; and ?
other temporary investments of $6.5 million made in 2003.
Partially offsetting the increases in net cash used in investing activities was a decrease in construction expenditures of $22.1 million in 2003 compared to 2002 primarily due to the power uprate project in 2002.
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis 25 proposed in the Initial Decision are arbitrary and are so complex that they would be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's 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.
If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average.
If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost.
The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth.
This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.
An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power.
Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans.
Of these, Entergy Arkansas is the least dependent upon gas-fired generation.
Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies.
Considerable uncertainty exists regarding future gas prices.
Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu during the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004.
Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004.
Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:
## Table 1 ##
Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers.
The timing of recovery of these costs in rates could be the subject of additional proceedings at the APSC and elsewhere, however, and a delay in full recovery of any increased allocation of production costs could result in additional financing requirements.
Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation.
In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC ALJ's Initial Decision would have on Entergy Arkansas' customers.
The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis 30 whether other procedural steps are necessary.
The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy.
Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time.
A hearing in the AFC proceeding is currently scheduled to commence in August 2005.
Federal Legislation Federal legislation intended to facilitate wholesale competition in the electric power industry has been seriously considered by the United States Congress for the past several years.
In the last Congress, both the House and Senate passed separate versions of comprehensive energy legislation, negotiated a conference package, and fell two votes short of bringing the conferenced bill up for a vote in the Senate.
The bill contained electricity provisions that would, among other things, allow for participant funding of transmission interconnections and upgrades, repeal PUHCA, repeal or modify PURPA, enact a mechanism for establishing enforceable reliability standards, provide the FERC with new authority over utility mergers and acquisitions, and codify the FERC's authority over market- based rates.
It is expected that the United States House and Senate will again craft and consider energy legislation in the 109th Congress.
Market and Credit Risks Market risk is the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions.
Entergy is exposed to the following significant market risks: ?
The commodity price risk associated with Entergy's Non-Utility Nuclear and Energy Commodity Services segments.  ?
The foreign currency exchange rate risk associated with certain of Entergy's contractual obligations.  ?
The interest rate and equity price risk associated with Entergy's investments in decommissioning trust funds.
Entergy is also exposed to credit risk.
Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement.
Where it is a significant consideration, counterparty credit risk is addressed in the discussions that follow.
Commodity Price Risk Power Generation 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.
Entergy's Non-Utility Nuclear business has entered into PPAs and other contracts to sell the power produced by its power plants at prices established in the PPAs.
Entergy continues to pursue opportunities to extend the existing PPAs and to enter into new PPAs with other parties.
Following is a summary of the amount of the Non-Utility Nuclear business' output that is currently sold forward under physical or financial contracts at fixed prices:
## Table 2 ##
Entergy Corporation Notes to Consolidated Financial Statements 82 Upon implementation of SFAS 143 in 2003, assets and liabilities increased $1.1 billion for the U. S.  Utility segment as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $287 million, reducing accumulated depreciation by $361 million, and recording the related regulatory assets of $422 million.
The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings by $21 million net-of-tax as a result of a one-time cumulative effect of accounting change.
In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for the domestic utility companies and System Energy include a component for removal costs that are not asset retirement obligations under SFAS 143.
In accordance with regulatory accounting principles, Entergy has recorded a regulatory asset for certain of its domestic utility companies and System Energy of $86.9 million as of December 31, 2004 and $72.4 million as of December 31, 2003 to reflect an estimate of incurred but uncollected removal costs previously recorded as a component of accumulated depreciation.
The decommissioning and retirement cost liability for certain of the domestic utility companies and System Energy includes a regulatory liability of $34.6 million as of December 31, 2004 and $26.8 million as of December 31, 2003 representing an estimate of collected but not yet incurred removal costs.
For the Non-Utility Nuclear business, the implementation of SFAS 143 resulted in a decrease in liabilities of $595 million due to reductions in decommissioning liabilities, a decrease in assets of $340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings in 2003 of $155 million net-of-tax as a result of a one-time cumulative effect of accounting change.
The cumulative decommissioning liabilities and expenses recorded in 2004 by Entergy were as follows:

<table><tr><td>2004</td><td>2003</td><td>2002</td><td>2001</td></tr><tr><td>(In Thousands)</td></tr><tr><td>$61,592</td><td>$19,064</td><td>$7,046</td><td>$13,853</td></tr></table>
<table><tr><td></td><td>Range of Annual Paymentsor (Receipts)</td><td>Average AnnualPayments or (Receipts)for 2005-2009 Period</td></tr><tr><td></td><td>(In Millions)</td><td>(In Millions)</td></tr><tr><td>Entergy Arkansas</td><td>$154 to $281</td><td>$215</td></tr><tr><td>Entergy Gulf States</td><td>-$130 to ($15)</td><td>-$63</td></tr><tr><td>Entergy Louisiana</td><td>-$199 to ($98)</td><td>-$141</td></tr><tr><td>Entergy Mississippi</td><td>-$16 to $8</td><td>$1</td></tr><tr><td>Entergy New Orleans</td><td>-$17 to ($5)</td><td>-$12</td></tr></table>
<table><tr><td></td><td> 2005</td><td> 2006</td><td> 2007</td><td> 2008</td><td> 2009</td></tr><tr><td> Non-Utility Nuclear:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Percent of planned generation sold forward:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unit-contingent</td><td>36%</td><td>20%</td><td>17%</td><td>1%</td><td>0%</td></tr><tr><td>Unit-contingent with availability guarantees</td><td>54%</td><td>52%</td><td>38%</td><td>25%</td><td>0%</td></tr><tr><td>Firm liquidated damages</td><td>4%</td><td>4%</td><td>2%</td><td>0%</td><td>0%</td></tr><tr><td>Total</td><td>94%</td><td>76%</td><td>57%</td><td>26%</td><td>0%</td></tr><tr><td>Planned generation (TWh)</td><td>34</td><td>35</td><td>34</td><td>34</td><td>35</td></tr><tr><td>Average contracted price per MWh</td><td>$39</td><td>$41</td><td>$42</td><td>$44</td><td>N/A</td></tr></table>

Question: Which year is Average contracted price per MWh the most?
Answer: 2008