LIQUIDITY The primary source of our liquidity is cash flow from operations.
Over the most recent two-year period, our operations have generated $5.6 billion in cash.
A substantial portion of this operating cash flow has been returned to shareholders through share repurchases and dividends.
We also use cash from operations to fund our capital expenditures and acquisitions.
We typically use a combination of cash, notes payable, and long-term debt, and occasionally issue shares of stock, to finance significant acquisitions.
As of May 26, 2019, we had $399 million of cash and cash equivalents held in foreign jurisdictions.
As a result of the TCJA, the historic undistributed earnings of our foreign subsidiaries were taxed in the U. S.  via the one-time repatriation tax in fiscal 2018.
We have re-evaluated our assertion and have concluded that although earnings prior to fiscal 2018 will remain permanently reinvested, we will no longer make a permanent reinvestment assertion beginning with our fiscal 2018 earnings.
As part of the accounting for the TCJA, we recorded local country withholding taxes related to certain entities from which we began repatriating undistributed earnings and will continue to record local country withholding taxes on all future earnings.
As a result of the transition tax, we may repatriate our cash and cash equivalents held by our foreign subsidiaries without such funds being subject to further U. S.  income tax liability (please see Note 14 to the Consolidated Financial Statements in Item 8 of this report for additional information).
Cash Flows from Operations
## Table 0 ##
During fiscal 2019, cash provided by operations was $2,807 million compared to $2,841 million in the same period last year.
The $34 million decrease was primarily driven by a $377 million decrease in net earnings and a $550 million change in current assets and liabilities, partially offset by a $598 million change in deferred income taxes.
The $550 million change in current assets and liabilities was primarily driven by a $413 million change in the timing of accounts payable, including the impact of longer payment terms implemented in prior fiscal years.
The change in deferred income taxes was primarily related to the $638 million provisional benefit from revaluing our net U. S.  deferred tax liabilities to reflect the new U. S.  corporate tax rate as a result of the TCJA in fiscal 2018.
We strive to grow core working capital at or below the rate of growth in our net sales.
For fiscal 2019, core working capital decreased 34 percent, compared to a net sales increase of 7 percent.
As of May 26, 2019, our core working capital balance totaled $385 million, down 34 percent versus last year, this is primarily driven by continued benefits from our payment terms extension program and lower inventory balances.
In fiscal 2018, core working capital decreased 27 percent, compared to a net sales increase of 1 percent.
Prospective Capital Requirements The estimated cost, as of Dec.  31, 2000, of the capital expenditure programs of Xcel Energy and its subsidiaries and other capital requirements for the years 2001, 2002 and 2003 are shown in the table below.
## Table 1 ##
The capital expenditure programs of Xcel Energy are subject to continuing review and modification.
Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs.
In addition, Xcel Energy’s ongoing evaluation of merger, acquisition and divestiture opportunities to support corporate strategies, address restructuring requirements and comply with future requirements to install emission control equipment may impact actual capital requirements.
For more information, see Notes 12 and 14 to the Financial Statements.
Xcel Energy’s subsidiaries expect to invest significant amounts in nonregulated projects in the future.
Financing requirements for nonregulated project investments will vary depending on the success, timing and level of involvement in projects currently under consideration.
These investments could cause significant changes to the capital requirement estimates for nonregulated projects and property.
Long-term financing may be required for such investments.
NRG expects to invest approximately $3.1 billion in 2001 for nonregulated projects and property, which include acquisitions and project investments.
NRG’s future capital requirements may vary significantly.
For 2001, NRG’s capital requirements reflect expected acquisitions of existing generation facilities, including the Conectiv fossil assets, North Valmy, LS Power, Clark gas-fired assets, Reid Gardner coal-fired assets and the Bridgeport and New Haven Harbor coal-fired facilities.
Common Stock Dividend Xcel Energy initially adopted a dividend of $1.50 per share on an annual basis for 2000.
Future dividend levels will be dependent upon Xcel Energy’s results of operations, financial position, cash flows and other factors, and will be evaluated by the Xcel Energy board of directors.
Capital Sources Xcel Energy expects to meet future financing requirements by periodically issuing long-term debt, short-term debt, common stock and preferred securities to maintain desired capitalization ratios.
Over the long term, Xcel Energy’s equity investments in and acquisitions of nonregulated projects are expected to be financed at the nonregulated subsidiary level from internally generated funds or the issuance of subsidiary debt.
Financing requirements for the nonregulated projects, in excess of equity contributions from partners, are expected to be fulfilled through project or subsidiary debt and in the case of NRG, additional common equity or preferred offerings to the public.
The financing needs are subject to continuing review and can change depending on market and business conditions and changes, if any, in the construction programs and other capital requirements of Xcel Energy and its subsidiaries.
NRG Initial Public Offering (IPO) During the second quarter of 2000, NRG completed an IPO of approximately 32.4 million shares priced at $15 per share.
Upon completion of the IPO, Xcel Energy owns approximately 147.6 million Class A shares of NRG common stock, or 82 percent of NRG’s outstanding shares.
Management has concluded that this offering of NRG stock did not affect Xcel Energy’s ability to use the pooling-of-interests method of accounting for the merger of NSP and NCE.
The offering’s net proceeds of approximately $454 million were used exclusively by NRG for general corporate purposes, including funding a portion of NRG’s project investments and other capital requirements for 2000.
No proceeds of this offering were received by Xcel Energy.
A portion of the proceeds was accounted for as a gain on the sale of 18 percent of Xcel Energy’s ownership in NRG.
This gain of $216 million was not recorded in earnings, but is consistent with Xcel Energy’s accounting policy, which was recorded as an increase in the common stock premium component of stockholders’ equity.
During 2000, Xcel Energy’s board of directors authorized NRG to raise up to $600 million of equity through a follow-on offering.
NRG expects to issue up to 18.4 million shares of common stock in March 2001.
If all 18.4 million shares of common stock are issued, Xcel Energy’s ownership interest in NRG will decline to approximately 75 percent.
In addition, NRG expects to issue 8 million equity units in March 2001.
Each equity unit comprises a debenture and an obligation to acquire one share of NRG common stock no later than 2004.
The ultimate issuance of common stock, number of shares issued and amount of capital raised will be dependent upon market conditions.
No proceeds of any such offering would be received by Xcel Energy.
If Xcel Energy’s ownership interest in NRG declines to less than 80 percent, then NRG will no longer be included in Xcel Energy’s federal consolidated income tax return.
We do not expect this to have a material impact on our earnings.
defendants opposed.
On Sept.  30, 2005, the U. S.  District Court granted plaintiffs’ motion for class certification.
On Oct.  17, 2005, defendants filed a petition with the Second Circuit Court of Appeals challenging the class certification.
On Dec.  5, 2005, e prime reached a tentative settlement with the plaintiffs that received final court approval in May 2006.
The settlement was paid by e prime and it did not have a material financial impact on Xcel Energy.
Department of Labor Audit — In 2001, Xcel Energy received notice from the U. S.  DOL Employee Benefit Security Administration that it intended to audit the Xcel Energy pension plan.
After multiple on-site meetings and interviews with Xcel Energy personnel, the DOL indicated on Sept.  18, 2003, that it was prepared to take the position that Xcel Energy, as plan sponsor and through its delegate, the Pension Trust Administration Committee, breached its fiduciary duties under ERISA with respect to certain investments made in limited partnerships and hedge funds in 1997 and 1998.
The DOL has offered to conclude the audit if Xcel Energy is willing to contribute to the plan the full amount of losses from the questioned investments, or approximately $7 million.
On July 19, 2004, Xcel Energy formally responded with a letter to the DOL that asserted no fiduciary violations have occurred and extended an offer to meet to discuss the matter further.
In 2005, and again in January 2006, the DOL submitted two additional requests for information related to the investigation, and Xcel Energy submitted timely responses to each request.
On June 12, 2006, the DOL issued a letter to the Xcel Energy Pension Trust Administration Committee indicating that, although there may have been a breach of the Committee’s fiduciary obligations under ERISA, the DOL will not pursue any action against the Committee or the pension plan with respect to these alleged breaches due, in part, to the steps the Committee has taken in outsourcing certain investment management and administration functions to third parties.
NewMech vs.  Northern States Power Company — On May 16, 2006, NewMech served and filed a complaint against NSPMinnesota, Southern Minnesota Municipal Power Agency (SMMPA), and Benson Engineering in the Minnesota State District Court, Sherburne County, alleging entitlement to payment in the amount of approximately $4.2 million for unpaid costs allegedly associated with construction work done by NewMech at NSP-Minnesota and SMMPA’s jointly owned Sherco 3 generating plant in 2005.
NewMech had previously served a mechanic’s lien, and sought, through this action, foreclosure of the lien and sale of the property.
NewMech additionally sought the claimed damages as a result of an alleged breach of contract by NSP-Minnesota.
NSP-Minnesota, SMMPA and Benson filed answers denying NewMech’s allegations.
Additionally, NSP-Minnesota and SMMPA counterclaimed for damages in excess of $7 million for breach of contract, delay in contract performance, misrepresentation and fraudulent inducement to enter into the contract and slander of title.
A confidential settlement of the dispute was reached on Sept.  29, 2006 and it did not have a material financial impact on Xcel Energy.
Additional Information For more discussion of legal claims and environmental proceedings, see Note 14 to the Consolidated Financial Statements under Item 8, incorporated by reference.
For a discussion of proceedings involving utility rates and other regulatory matters, see Pending and Recently Concluded Regulatory Proceedings under Item 1, Management’s Discussion and Analysis under Item 7, and Note 13 to the Consolidated Financial Statements under Item 8, incorporated by reference.
Item 4 — Submission of Matters to a Vote of Security Holders No issues were submitted for a vote during the fourth quarter of 2006.
PART II Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Quarterly Stock Data Xcel Energy’s common stock is listed on the New York Stock Exchange (NYSE).
The trading symbol is XEL.
The following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 2006 and 2005 and the dividends declared per share during those quarters.
## Table 2 ##
and liabilities in its consolidated statement of income.
The components of unamortized regulatory assets and liabilities of continuing operations shown on the consolidated balance sheets at Dec.  31 are: See Note(s) Remaining Amortization
## Table 3 ##
(a) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
(b) Earns a return on investment in the ratemaking process.
These amounts are amortized consistent with recovery in rates.
(c) Includes the fair value of certain long-term purchased power agreements used to meet energy capacity requirements.
(d) Included in other current liabilities of $331,419 and $268,720 at Dec.  31, 2008 and 2007, respectively, in the consolidated balance sheets.20.
Segments and Related Information The regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker.
Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided.
These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Given the similarity of the regulated electric utility operations of its utility subsidiaries, and the similarity of the regulated natural gas utility operations its utility subsidiaries, Xcel Energy has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.  ?
Xcel Energy’s regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico.
In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.
Regulated electric utility also includes commodity trading operations.  ?
Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.

<table><tr><td></td><td>Fiscal Year</td></tr><tr><td>In Millions</td><td>2019</td><td>2018</td></tr><tr><td>Net earnings, including earnings attributable to redeemable and noncontrollinginterests</td><td>$1,786.2</td><td>$2,163.0</td></tr><tr><td>Depreciation and amortization</td><td>620.1</td><td>618.8</td></tr><tr><td>After-taxearnings from joint ventures</td><td>-72.0</td><td>-84.7</td></tr><tr><td>Distributions of earnings from joint ventures</td><td>86.7</td><td>113.2</td></tr><tr><td>Stock-based compensation</td><td>84.9</td><td>77.0</td></tr><tr><td>Deferred income taxes</td><td>93.5</td><td>-504.3</td></tr><tr><td>Pension and other postretirement benefit plan contributions</td><td>-28.8</td><td>-31.8</td></tr><tr><td>Pension and other postretirement benefit plan costs</td><td>6.1</td><td>4.6</td></tr><tr><td>Divestitures loss</td><td>30.0</td><td>-</td></tr><tr><td>Restructuring, impairment, and other exit costs</td><td>235.7</td><td>126.0</td></tr><tr><td>Changes in current assets and liabilities, excluding the effects of acquisitions anddivestitures</td><td>-7.5</td><td>542.1</td></tr><tr><td>Other, net</td><td>-27.9</td><td>-182.9</td></tr><tr><td>Net cash provided by operating activities</td><td>$2,807.0</td><td>$2,841.0</td></tr></table>
<table><tr><td> </td><td> 2001</td><td> 2002</td><td> 2003</td></tr><tr><td> </td><td colspan="3"> (Millions of dollars)  </td></tr><tr><td>Electric utility</td><td>$931</td><td>$979</td><td>$962</td></tr><tr><td>Gas utility</td><td>162</td><td>209</td><td>146</td></tr><tr><td>Common utility</td><td>114</td><td>107</td><td>38</td></tr><tr><td>Total utility</td><td>1,207</td><td>1,295</td><td>1,146</td></tr><tr><td>NRG</td><td>3,138</td><td>1,341</td><td>1,517</td></tr><tr><td>Other nonregulated</td><td>91</td><td>53</td><td>12</td></tr><tr><td>Total capital expenditures</td><td>4,436</td><td>2,689</td><td>2,675</td></tr><tr><td>Sinking funds and debt maturities</td><td>605</td><td>311</td><td>663</td></tr><tr><td>Total capital requirements</td><td>$5,041</td><td>$3,000</td><td>$3,338</td></tr></table>
<table><tr><td> </td><td> High</td><td> Low</td><td> Dividends</td></tr><tr><td> 2006</td><td></td><td></td><td></td></tr><tr><td>First Quarter</td><td>$19.61</td><td>$17.91</td><td>$0.2150</td></tr><tr><td>Second Quarter</td><td>$19.76</td><td>$17.80</td><td>$0.2225</td></tr><tr><td>Third Quarter</td><td>$21.05</td><td>$18.96</td><td>$0.2225</td></tr><tr><td>Fourth Quarter</td><td>$23.63</td><td>$20.56</td><td>$0.2225</td></tr></table>
<table><tr><td> </td><td> See Note(s)</td><td> Remaining Amortization Period</td><td> 2008</td><td> 2007</td></tr><tr><td> </td><td colspan="4"> (Thousands of Dollars) </td></tr><tr><td> Regulatory Assets</td><td></td><td></td><td></td><td></td></tr><tr><td>Current regulatory asset — Unrecovered fuel costs</td><td>1</td><td>Less than one year</td><td>$32,843</td><td>$73,415</td></tr><tr><td>Pension and employee benefit obligations</td><td>12</td><td>Various</td><td>$1,212,542</td><td>$387,127</td></tr><tr><td>Net AROs<sup>(a)</sup></td><td>1,17</td><td>Plant lives</td><td>299,294</td><td>39,891</td></tr><tr><td>AFDC recorded in plant<sup>(b)</sup></td><td>1</td><td>Plant lives</td><td>220,354</td><td>189,698</td></tr><tr><td>Contract valuation adjustments<sup>(c)</sup></td><td>14</td><td>Term of related contract</td><td>150,723</td><td>106,649</td></tr><tr><td>Conservation programs<sup>(b)</sup></td><td></td><td>Various</td><td>117,188</td><td>119,839</td></tr><tr><td>Environmental costs</td><td>16,17</td><td>Generally four to six years once actual expenditures are incurred</td><td>75,880</td><td>55,038</td></tr><tr><td>Losses on reacquired debt</td><td>1</td><td>Term of related debt</td><td>66,268</td><td>73,002</td></tr><tr><td>Renewable resource costs</td><td></td><td>One to two years</td><td>55,868</td><td>51,785</td></tr><tr><td>Nuclear outage costs</td><td>16</td><td>Generally 18-24 months</td><td>40,690</td><td>—</td></tr><tr><td>Purchased power contracts costs</td><td>14</td><td>Term of related contract</td><td>20,716</td><td>—</td></tr><tr><td>Unrecovered natural gas costs</td><td>1</td><td>One to two years</td><td>14,657</td><td>22,505</td></tr><tr><td>State commission accounting adjustments<sup>(b)</sup></td><td></td><td>Various</td><td>13,148</td><td>13,828</td></tr><tr><td>Rate case costs</td><td>1</td><td>Various</td><td>12,085</td><td>9,630</td></tr><tr><td>MISO Day 2 costs</td><td>1</td><td>To be determined in future rate proceedings</td><td>11,783</td><td>12,035</td></tr><tr><td>Nuclear fuel storage</td><td></td><td>Four years</td><td>9,652</td><td>11,578</td></tr><tr><td>Nuclear decommissioning costs</td><td></td><td>To be determined in future rate proceedings</td><td>8,775</td><td>11,149</td></tr><tr><td>Other</td><td></td><td>Various</td><td>27,656</td><td>11,689</td></tr><tr><td>Total noncurrent regulatory assets</td><td></td><td></td><td>$2,357,279</td><td>$1,115,443</td></tr><tr><td> Regulatory Liabilities</td><td></td><td></td><td></td><td></td></tr><tr><td>Current regulatory liability — Overrecovered fuel costs<sup>(d)</sup></td><td></td><td></td><td>$134,212</td><td>$34,451</td></tr><tr><td>Plant removal costs</td><td>1,17</td><td></td><td>$925,472</td><td>$906,996</td></tr><tr><td>Contract valuation adjustments<sup>(c)</sup></td><td>14</td><td></td><td>124,676</td><td>108,533</td></tr><tr><td>Investment tax credit deferrals</td><td></td><td></td><td>68,313</td><td>72,686</td></tr><tr><td>Deferred income tax adjustments</td><td>1</td><td></td><td>42,619</td><td>59,282</td></tr><tr><td>Nuclear outage costs collected in advance from customers</td><td></td><td></td><td>13,678</td><td>—</td></tr><tr><td>Gain on sale of emission allowances</td><td>1</td><td></td><td>8,153</td><td>21,334</td></tr><tr><td>Interest on income tax refunds</td><td></td><td></td><td>1,736</td><td>3,472</td></tr><tr><td>Pension and employee benefit obligations</td><td>12</td><td></td><td>—</td><td>205,133</td></tr><tr><td>Other</td><td></td><td></td><td>9,949</td><td>12,551</td></tr><tr><td>Total noncurrent regulatory liabilities</td><td></td><td></td><td>$1,194,596</td><td>$1,389,987</td></tr></table>

Question: What is the growing rate of Rate case costs in the year with the most Renewable resource costs?
Answer: 0.25493