Entergy Arkansas, Inc.  Management's Financial Discussion and Analysis 151 Operating Activities Cash flow from operations increased $8.8 million in 2004 compared to 2003 primarily due to income tax benefits received in 2004, and increased recovery of deferred fuel costs.
This increase was substantially offset by money pool activity.
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 $1.171 billion deduction for Entergy Arkansas on Entergy's 2003 income tax return.
There was no cash benefit from the method change in 2003.
In 2004, Entergy Arkansas realized $173 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.
As of December 31, 2004, Entergy Arkansas has a net operating loss (NOL) carryforward for tax purposes of $766.9 million, principally resulting from the change in tax accounting method related to cost of goods sold.
If the tax accounting method change is sustained, Entergy Arkansas expects to utilize the NOL carryforward through 2006.
Cash flow from operations increased $80.1 million in 2003 compared to 2002 primarily due to income taxes paid of $2.2 million in 2003 compared to income taxes paid of $83.9 million in 2002, and money pool activity.
This increase was partially offset by decreased recovery of deferred fuel costs in 2003.
Entergy Arkansas' receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years:
## Table 0 ##
Money pool activity used $92.7 million of Entergy Arkansas' operating cash flow in 2004, provided $73.4 million in 2003, and provided $19.5 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 The decrease of $68.1 million in net cash used in investing activities in 2004 compared to 2003 was primarily due to a decrease in construction expenditures resulting from less transmission upgrade work requested by merchant generators in 2004 combined with lower spending on customer support projects in 2004.
The increase of $88.1 million in net cash used in investing activities in 2003 compared to 2002 was primarily due to an increase in construction expenditures of $57.4 million and the maturity of $38.4 million of other temporary investments in the first quarter of 2002.
Construction expenditures increased in 2003 primarily due to the following: ?
a FERC ruling that shifted responsibility for transmission upgrade work performed for independent power producers to Entergy Arkansas; and ?
the ANO 1 steam generator, reactor vessel head, and transformer replacement project.
Financing Activities The decrease of $90.7 million in net cash used in financing activities in 2004 compared to 2003 was primarily due to the net redemption of $2.4 million of long-term debt in 2004 compared to $109.3 million in 2003, partially offset by the payment of $16.2 million more in common stock dividends during the same period.
## Table 1 ##
The volume/weather variance resulted primarily from an increase of 1,179 GWh in electricity usage in the industrial sector.
Billed usage also increased a total of 291 GWh in the residential, commercial, and governmental sectors.
The increase in net wholesale revenue is primarily due to an increase in sales volume to municipal and co-op customers.
Summer capacity charges variance is due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of the amortization in 2004.
The amortization of these capacity charges began in June 2002 and ended in May 2003.
The price applied to unbilled sales variance resulted primarily from an increase in the fuel price applied to unbilled sales.
Fuel recovery revenues represent an under-recovery of fuel charges that are recovered in base rates.
Entergy Gulf States recorded $22.6 million of provisions in 2004 for potential rate refunds.
These provisions are not included in the Net Revenue table above because they are more than offset by provisions recorded in 2003.
Gross operating revenues, fuel and purchased power expenses, and other regulatory credits Gross operating revenues increased primarily due to an increase of $187.8 million in fuel cost recovery revenues as a result of higher fuel rates in both the Louisiana and Texas jurisdictions.
The increases in volume/weather and wholesale revenue, discussed above, also contributed to the increase.
Fuel and purchased power expenses increased primarily due to: ?
increased recovery of deferred fuel costs due to higher fuel rates; ?
increases in the market prices of natural gas, coal, and purchased power; and ?
an increase in electricity usage, discussed above.
Other regulatory credits increased primarily due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of amortization in 2004.
The amortization of these charges began in June 2002 and ended in May 2003.2003 Compared to 2002 Net revenue, which is Entergy Gulf States' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits.
Following is an analysis of the change in net revenue comparing 2003 to 2002.
Domestic utility companies and System Energy Notes to Respective Financial Statements 333 Effective January 1, 1993, Entergy adopted SFAS 106, which required a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions.
At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $241.4 million for Entergy (other than Entergy Gulf States) and $128 million for Entergy Gulf States.
Such obligations are being amortized over a 20-year period that began in 1993.
Entergy Arkansas, the portion of Entergy Gulf States regulated by the PUCT, Entergy Mississippi, and Entergy New Orleans have received regulatory approval to recover SFAS 106 costs through rates.
Entergy Arkansas began recovery in 1998, pursuant to an APSC order.
This order also allowed Entergy Arkansas to amortize a regulatory asset (representing the difference between SFAS 106 costs and cash expenditures for other postretirement benefits incurred for a five-year period that began January 1, 1993) over a 15-year period that began in January 1998.
The LPSC ordered the portion of Entergy Gulf States regulated by the LPSC and Entergy Louisiana to continue the use of the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions.
However, the LPSC retains the flexibility to examine individual companies' accounting for postretirement benefits to determine if special exceptions to this order are warranted.
Pursuant to regulatory directives, Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, the portion of Entergy Gulf States regulated by the PUCT, and System Energy fund postretirement benefit obligations collected in rates.
System Energy is funding, on behalf of Entergy Operations, postretirement benefits associated with Grand Gulf.
Entergy Louisiana and Entergy Gulf States continue to recover a portion of these benefits regulated by the LPSC and FERC on a pay-as-you-go basis.
Components of Net Other Postretirement Benefit Cost Total 2004, 2003, and 2002 other postretirement benefit costs of the domestic utility companies and System Energy, including amounts capitalized and deferred, included the following components
## Table 2 ##
Notes to Consolidated Financial Statements 74 The annual long-term debt maturities (excluding lease obligations) for debt outstanding as of December 31, 2004, for the next five years are as follows:
## Table 3 ##
In November 2000, Entergy's Non-Utility Nuclear business purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction.
Entergy issued notes to NYPA with seven annual installments of approximately $108 million commencing one year from the date of the closing, and eight annual installments of $20 million commencing eight years from the date of the closing.
These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%.
In accordance with the purchase agreement with NYPA, the purchase of Indian Point 2 in 2001 resulted in Entergy's Non-Utility Nuclear business becoming liable to NYPA for an additional $10 million per year for 10 years, beginning in September 2003.
This liability was recorded upon the purchase of Indian Point 2 in September 2001, and is included in the note payable to NYPA balance above.
In July 2003, a payment of $102 million was made prior to maturity on the note payable to NYPA.
Under a provision in a letter of credit supporting these notes, if certain of the domestic utility companies or System Energy were to default on other indebtedness, Entergy could be required to post collateral to support the letter of credit.
Covenants in the Entergy Corporation notes require it to maintain a consolidated debt ratio of 65% or less of its total capitalization.
If Entergy's debt ratio exceeds this limit, or if Entergy or certain of the domestic utility companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the notes' maturity dates may occur.
The long-term securities issuances of Entergy Corporation, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and System Energy also are limited to amounts authorized by the SEC.
Under its current SEC order, and without further authorization, Entergy Corporation cannot incur additional indebtedness or issue other securities unless (a) it and each of its public utility subsidiaries maintain a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of Entergy Corporation that are rated, are rated investment grade by at least one nationally recognized statistical rating agency.
Under their current SEC orders, and without further authorization, Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi cannot incur additional indebtedness or issue other securities unless (a) the issuer and Entergy Corporation maintains a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of the issuer (other than preferred stock of Entergy Gulf States), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade.
Junior Subordinated Deferrable Interest Debentures and Implementation of FIN 46 Entergy implemented FASB Interpretation No.46, "Consolidation of Variable Interest Entities" effective December 31, 2003.
FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among their investors.
Variable interest entities (VIEs), generally, are entities that do not have sufficient equity to permit the entity to finance its operations without additional financial support from its equity interest holders and/or the group of equity interest holders are collectively not able to exercise control over the entity.
The primary beneficiary is the party that absorbs a majority of the entity's expected losses, receives a majority of its expected residual returns, or both as a result of holding the variable interest.
A company may have an interest in a VIE through ownership or other contractual rights or obligations.
Entergy Louisiana Capital I, Entergy Arkansas Capital I, and Entergy Gulf States Capital I (Trusts) were established as financing subsidiaries of Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States,
Entergy Corporation and Subsidiaries Notes to Financial Statements was contingent upon receiving approval from the NRC, which was received in January 2017. ?
As a result of the agreement with NYPA, in the third quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and recorded asset retirement obligations for the decommissioning liabilities.
At December 31, 2016, the fair values of the decommissioning trust funds held by NYPA were $719 million for the Indian Point 3 plant and $785 million for the FitzPatrick plant.
The fair values were based on the trust statements received from NYPA and were valued by the fund administrator using net asset value as a practical expedient.
Accordingly, these funds were not assigned a level in the fair value hierarchy.
For Indian Point 3, the receivable for the beneficial interest in the decommissioning trust fund was recorded in other deferred debits on the consolidated balance sheet as of December 31, 2016.
For FitzPatrick, the receivable for the beneficial interest in the decommissioning trust fund was classified as held for sale within other deferred debits on the consolidated balance sheet as of December 31, 2016.
In January 2017, NYPA transferred to Entergy the Indian Point 3 decommissioning trust funds with a fair value of $726 million and the FitzPatrick decommissioning trust fund with a fair value of $793 million.
In March 2017, Entergy closed on the sale of the FitzPatrick plant to Exelon.
As part of the transaction, Entergy transferred the FitzPatrick decommissioning trust fund to Exelon.
The FitzPatrick decommissioning trust fund had a disposition-date fair value of $805 million.
See Note 9 to the financial statements for further discussion of the decommissioning agreements with NYPA and see Note 14 to the financial statements for further discussion of the sale of FitzPatrick.
Entergy records decommissioning trust funds on the balance sheet at their fair value. ?
?Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/ (losses) on investment securities in other regulatory liabilities/assets. ?
?For the 30% interest in River Bend formerly owned by Cajun, Entergy Louisiana records an offsetting amount in other deferred credits for the excess trust earnings not currently expected to be needed to decommission the plant.
?Decommissioning trust funds for Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. ?
?Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity because these assets are classified as available for sale. ?
?Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings. ?
?Generally, Entergy records realized gains and losses on its debt and equity securities using the specific identification method to determine the cost basis of its securities.
The securities held as of December?31, 2017 and 2016 are summarized 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>$23,561</td><td>-$69,153</td><td>$4,279</td><td>$23,794</td></tr></table>
<table><tr><td></td><td>(In Millions)</td></tr><tr><td>2003 net revenue</td><td>$1,110.1</td></tr><tr><td>Volume/weather</td><td>26.7</td></tr><tr><td>Net wholesale revenue</td><td>13.0</td></tr><tr><td>Summer capacity charges</td><td>5.5</td></tr><tr><td>Price applied to unbilled sales</td><td>4.8</td></tr><tr><td>Fuel recovery revenues</td><td>-14.2</td></tr><tr><td>Other</td><td>3.9</td></tr><tr><td>2004 net revenue</td><td>$1,149.8</td></tr></table>
<table><tr><td>  2004</td><td> Entergy Arkansas</td><td> Entergy Gulf States</td><td> Entergy Louisiana</td><td> Entergy Mississippi</td><td> Entergy New Orleans</td><td> System Energy</td></tr><tr><td></td><td colspan="6">(In Thousands)</td></tr><tr><td>Service cost - benefits earned during the period</td><td> $3,860</td><td> $5,328</td><td> $2,371</td><td> $1,213</td><td> $662</td><td> $1,389</td></tr><tr><td>Interest cost on APBO</td><td>10,075</td><td>11,050</td><td>6,641</td><td>3,222</td><td>3,204</td><td>1,430</td></tr><tr><td>Expected return on assets</td><td>-6,210</td><td>-4,995</td><td>-</td><td>-2,554</td><td>-2,263</td><td>-1,362</td></tr><tr><td>Amortization of transition obligation</td><td> 1,068</td><td> 4,589</td><td> 1,202</td><td> 431</td><td> 2,121</td><td> 15</td></tr><tr><td>Amortization of prior service cost</td><td>27</td><td>-</td><td>98</td><td>16</td><td>38</td><td>-361</td></tr><tr><td>Recognized net loss</td><td>3,937</td><td>1,620</td><td>2,003</td><td>1,503</td><td>522</td><td>358</td></tr><tr><td>Net other postretirement benefit cost</td><td> $12,757</td><td> $17,592</td><td> $12,315</td><td> $3,831</td><td> $4,284</td><td> $1,469</td></tr></table>
<table><tr><td></td><td>(In Thousands)</td></tr><tr><td>2005</td><td>$467,298</td></tr><tr><td>2006</td><td>$75,896</td></tr><tr><td>2007</td><td>$199,539</td></tr><tr><td>2008</td><td>$747,246</td></tr><tr><td>2009</td><td>$512,584</td></tr></table>

Question: what are the provisions for potential rate refunds as a percentage of net revenue in 2004?
Answer: 0.01966