Our international crude oil production is relatively sweet and is generally sold in relation to the Brent crude benchmark.
The differential between WTI and Brent average prices widened significantly in 2011 and remained in 2012 in comparison to almost no differential in 2010.
Natural gas – A significant portion of our natural gas production in the lower 48 states of the U. S.  is sold at bid-week prices or first-of-month indices relative to our specific producing areas.
Average Henry Hub settlement prices for natural gas were lower in 2012 than in recent years.
A decline in average settlement date Henry Hub natural gas prices began in September 2011 and continued into 2012.
Although prices stabilized in late 2012, they have not increased appreciably.
Our other major natural gas-producing regions are E. G.  and Europe.
In the case of E. G,.
our natural gas sales are subject to term contracts, making realizations less volatile.
Because natural gas sales from E. G.  are at fixed prices, our worldwide reported average natural gas realizations may not fully track market price movements.
Natural gas prices in Europe have been significantly higher than in the U. S.  Oil Sands Mining The OSM segment produces and sells various qualities of synthetic crude oil.
Output mix can be impacted by operational problems or planned unit outages at the mines or upgrader.
Sales prices for roughly two-thirds of the normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil marker, primarily WCS.
In 2012, the WCS discount from WTI had increased, putting downward pressure on our average realizations.
The operating cost structure of the OSM operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime.
Per-unit costs are sensitive to production rates.
Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO") natural gas sales index and crude oil prices, respectively.
The table below shows average benchmark prices that impact both our revenues and variable costs.
## Table 0 ##
(a) Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
(b) Monthly average day ahead index.
Integrated Gas Our IG operations include production and marketing of products manufactured from natural gas, such as LNG and methanol, in E. G.  World LNG trade in 2012 has been estimated to be 240 mmt.
Long-term, LNG continues to be in demand as markets seek the benefits of clean burning natural gas.
Market prices for LNG are not reported or posted.
In general, LNG delivered to the U. S.  is tied to Henry Hub prices and will track with changes in U. S.  natural gas prices, while LNG sold in Europe and Asia is indexed to crude oil prices and will track the movement of those prices.
We have a 60 percent ownership in an LNG production facility in E. G. , which sells LNG under a long-term contract at prices tied to Henry Hub natural gas prices.
Gross sales from the plant were 3.8 mmt, 4.1 mmt and 3.7 mmt in 2012, 2011 and 2010.
We own a 45 percent interest in a methanol plant located in E. G.  through our investment in AMPCO.
Gross sales of methanol from the plant totaled 1.1 mmt, 1.0 mmt and 0.9 mmt in 2012, 2011 and 2010.
Methanol demand has a direct impact on AMPCO’s earnings.
Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices.
World demand for methanol in 2012 has been estimated to be 49 mmt.
Our plant capacity of 1.1 mmt is about 2 percent of world demand.
17.
Segments and Related Information 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.
In October 2005, SPS reached a definitive agreement to sell its delivery system operations in Oklahoma, Kansas and a small portion of Texas to Tri-County Electric Cooperative.
Effective July 31, 2006, SPS completed the sale to Tri-County Electric Cooperative for $24.5 million and a gain of $6.1 million was recognized.
SPS now provides wholesale service to Tri-County Electric Cooperative.  ?
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.
Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the All Other category.
Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.
To report income from continuing operations for Regulated Electric and Regulated Natural Gas Utility segments, Xcel Energy must assign or allocate all costs and certain other income.
In general, costs are: ?
directly assigned wherever applicable; ?
allocated based on cost causation allocators wherever applicable; and ?
allocated based on a general allocator for all other costs not assigned by the above two methods.
The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements.
These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which are separately determined for each segment.
Xcel Energy evaluates performance by each legal entity based on profit or loss generated from the product or service provided.
## Table 1 ##
counterparty valuations, internal valuations and broker quotes.
There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.
At Dec.  31, 2006 and 2005, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense by approximately $7.0 million and $10.3 million, respectively.
See Note 11 to the Consolidated Financial Statements for a discussion of Xcel Energy and its subsidiaries’ interest rate swaps.
Xcel Energy and its subsidiaries also maintain trust funds, as required by the NRC, to fund costs of nuclear decommissioning.
These trust funds are subject to interest rate risk and equity price risk.
As of Dec.  31, 2006 and 2005, these funds were invested primarily in domestic and international equity securities and fixed-rate fixed-income securities.
These funds may be used only for activities related to nuclear decommissioning.
The accounting for nuclear decommissioning recognizes that costs are recovered through rates; therefore fluctuations in equity prices or interest rates do not have an impact on earnings.
Credit Risk — Xcel Energy and its subsidiaries are also exposed to credit risk.
Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations.
Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.
Xcel Energy and its subsidiaries conduct standard credit reviews for all counterparties.
Xcel Energy employs additional credit risk control mechanisms, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.
The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.
At Dec.  31, 2006, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $8.1 million, while a decrease of 10 percent would have resulted in a decrease of $7.3 million.
Liquidity and Capital Resources Cash Flows
## Table 2 ##
Cash provided by operating activities for continuing operations increased $598 million during 2006.
The increase is primarily due to the timing of working capital activity.
Specifically, the collection of receivables and the collection of recoverable purchased natural gas and electric energy costs increased in 2006.
The increase in cash provided by operations was partially offset by the timing of cash expenditures for accounts payable.
Cash provided by operating activities for discontinued operations increased $150 million during 2006, largely due to the recognition of deferred tax assets related to NRG.
Cash provided by operating activities for continuing operations was basically unchanged for 2005 and 2004.
Cash provided by operating activities for discontinued operations increased $368 million during 2005 compared with 2004.
During 2004, Xcel Energy paid $752 million pursuant to the NRG settlement agreement, which was partially offset by tax benefits received.

<table><tr><td>Benchmark</td><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>WTI crude oil(Dollars per bbl)</td><td>$94.15</td><td>$95.11</td><td>$79.61</td></tr><tr><td>WCS(Dollars per bbl)<sup>(a)</sup></td><td>$73.18</td><td>$77.97</td><td>$65.31</td></tr><tr><td>AECO natural gas sales index(Dollars per mmbtu)<sup>(b)</sup></td><td>$2.39</td><td>$3.68</td><td>$3.89</td></tr></table>
<table><tr><td> </td><td> Regulated Electric Utility</td><td> Regulated Natural Gas Utility</td><td>All Other</td><td>Reconciling Eliminations</td><td> Consolidated Total</td></tr><tr><td> </td><td colspan="5"> (Thousands of Dollars)</td></tr><tr><td> 2006</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues from external customers</td><td>$7,608,018</td><td>$2,155,999</td><td>$76,287</td><td>$—</td><td>$9,840,304</td></tr><tr><td>Intersegment revenues</td><td>820</td><td>12,296</td><td>—</td><td>-13,116</td><td>—</td></tr><tr><td>Total revenues</td><td>$7,608,838</td><td>$2,168,295</td><td>$76,287</td><td>$-13,116</td><td>$9,840,304</td></tr><tr><td>Depreciation and amortization</td><td>$711,930</td><td>$94,356</td><td>$15,612</td><td>$—</td><td>$821,898</td></tr><tr><td>Financing costs, mainly interest expense</td><td>302,114</td><td>44,965</td><td>133,558</td><td>-24,605</td><td>456,032</td></tr><tr><td>Income tax expense (benefit)</td><td>283,552</td><td>37,656</td><td>-139,797</td><td>—</td><td>181,411</td></tr><tr><td>Income (loss) from continuing operations</td><td>$503,119</td><td>$70,609</td><td>$51,570</td><td>$-56,617</td><td>$568,681</td></tr><tr><td> 2005</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues from external customers</td><td>$7,243,637</td><td>$2,307,385</td><td>$74,455</td><td>$—</td><td>$9,625,477</td></tr><tr><td>Intersegment revenues</td><td>767</td><td>17,732</td><td>—</td><td>-18,499</td><td>—</td></tr><tr><td>Total revenues</td><td>$7,244,404</td><td>$2,325,117</td><td>$74,455</td><td>$-18,499</td><td>$9,625,477</td></tr><tr><td>Depreciation and amortization</td><td>$662,236</td><td>$89,174</td><td>$15,911</td><td>$—</td><td>$767,321</td></tr><tr><td>Financing costs, mainly interest expense</td><td>301,185</td><td>47,145</td><td>108,538</td><td>-14,242</td><td>442,626</td></tr><tr><td>Income tax expense (benefit)</td><td>258,161</td><td>32,923</td><td>-117,545</td><td>—</td><td>173,539</td></tr><tr><td>Income (loss) from continuing operations</td><td>$440,578</td><td>$71,213</td><td>$35,733</td><td>$-48,486</td><td>$499,038</td></tr><tr><td> 2004</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues from external customers</td><td>$6,225,245</td><td>$1,915,514</td><td>$74,802</td><td>$—</td><td>$8,215,561</td></tr><tr><td>Intersegment revenues</td><td>1,132</td><td>8,735</td><td>—</td><td>-9,867</td><td>—</td></tr><tr><td>Total revenues</td><td>$6,226,377</td><td>$1,924,249</td><td>$74,802</td><td>$-9,867</td><td>$8,215,561</td></tr><tr><td>Depreciation and amortization</td><td>$610,127</td><td>$82,012</td><td>$13,816</td><td>$—</td><td>$705,955</td></tr><tr><td>Financing costs, mainly interest expense</td><td>299,768</td><td>48,757</td><td>100,784</td><td>-14,829</td><td>434,480</td></tr><tr><td>Income tax expense (benefit)</td><td>235,743</td><td>29,286</td><td>-103,094</td><td>—</td><td>161,935</td></tr><tr><td>Income (loss) from continuing operations</td><td>$466,307</td><td>$86,091</td><td>$12,173</td><td>$-42,307</td><td>$522,264</td></tr></table>
<table><tr><td> </td><td> 2006</td><td> 2005</td><td>2004</td></tr><tr><td> </td><td colspan="3">(Millions of Dollars)</td></tr><tr><td> Cash provided by (used in) operating activities</td><td></td><td></td><td></td></tr><tr><td>Continuing operations</td><td>$1,729</td><td>$1,131</td><td>$1,128</td></tr><tr><td>Discontinued operations</td><td>195</td><td>53</td><td>-315</td></tr><tr><td>Total</td><td>$1,924</td><td>$1,184</td><td>$813</td></tr></table>

Question: What do all Regulated Electric Utility sum up without those Regulated Electric Utility smaller than 500000, in 2006? (in Thousand)
Answer: 8823067.0