Table of Contents VALERO ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Cash Flow Hedges Cash flow hedges are used to hedge price volatility in certain forecasted feedstock and refined product purchases, refined product sales, and natural gas purchases.
The objective of our cash flow hedges is to lock in the price of forecasted feedstock, product or natural gas purchases, or refined product sales at existing market prices that we deem favorable.
As of December 31, 2012, we had the following outstanding commodity derivative instruments that were entered into to hedge forecasted purchases or sales of crude oil and refined products.
The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).
## Table 0 ##
Common Stock Dividends Per Share — Historically, Xcel Energy has paid quarterly dividends to its shareholders.
Dividends on common stock are paid as declared by the Board of Directors.
Dividends declared per share for the quarters of 2008, 2007 and 2006 are:
## Table 1 ##
Dividend and Other Capital-Related Restrictions — The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding.
Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only and not on a consolidated basis) is less than 25 percent.
For these purposes, the capitalization ratio is equal to (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt.
Based on this definition, the capitalization ratio at Dec.  31, 2008 and 2007, was 84 percent and 85 percent, respectively.
Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock.
In addition, NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock.
Even with these restrictions, NSP-Minnesota could have paid more than $999 million and $946 million in additional cash dividends on common stock at Dec.  31, 2008 and 2007, respectively.
The issuance of securities by Xcel Energy generally is not subject to regulatory approval.
However, utility financings and certain intra-system financings are subject to the jurisdiction of the applicable state regulatory commissions and/or the FERC under the Federal Power Act.  ?
PSCo currently has authorization to issue up to $250 million of long-term debt and up to $800 million of short-term debt at any one time outstanding.
PSCo has filed an application with the CPUC to increase the long-term debt authorization to $800 million.  ?
SPS currently has authorization to issue up to $400 million in short-term debt.  ?
NSP-Wisconsin currently has authorization to issue up to $250 million of long-term debt and $100 million of short-term debt.  ?
NSP-Minnesota has authorization to issue long-term securities provided the equity ratio remain between 46.26 percent and 56.54 percent and to issue short-term debt provided it does not exceed 15 percent of total capitalization.
Total capitalization for NSP-Minnesota cannot exceed $7.5 billion.
Xcel Energy believes these authorizations are adequate and will seek additional authorization when necessary, however, there can be no assurance that additional authorization will be granted on the timeframe or in the amounts requested.
The FERC has granted a blanket authorization for certain intra-system financings involving holding companies.
The utility subsidiaries participate in the money pool, in amounts ranging from $250 million for each of NSP-Minnesota and PSCo, to $100 million for SPS and $100 million for NSP-Wisconsin to borrow only from NSP-Minnesota.
NSP-Wisconsin is not authorized and does not participate in the money pool.
Stockholder Protection Rights Agreement — In June 2001, Xcel Energy adopted a Stockholder Protection Rights Agreement (Rights Agreement) pursuant to which each share of Xcel Energy’s common stock included one shareholder protection right.
On Dec.  11, 2008, Xcel Energy amended the Rights Agreement, changing the expiration date of the agreement from June 28, 2011 to Dec.  11, 2008.
Accordingly, the Rights Agreement expired on Dec.  11, 2008, and all associated rights have expired.10.
Share-Based Compensation Stock Options — Xcel Energy has incentive compensation plans under which stock options and other performance incentives are awarded to key employees.
In the past, Xcel Energy issued stock options, but has not granted stock
The following table presents the changes in Level 3 recurring fair value measurements for the year ended Dec.  31, 2008:
## Table 2 ##
Gains on Level 3 commodity derivatives recognized in earnings for the year ended Dec.  31, 2008, include $3.7 million of net unrealized gains relating to commodity derivatives held at Dec.  31, 2008.
Realized and unrealized gains and losses on commodity trading activities are included in electric revenues.
Realized and unrealized gains and losses on short-term wholesale activities reflect the impact of regulatory recovery and are deferred as regulatory assets and liabilities.
Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.16.
Rate Matters NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings — MPUC Base Rate NSP-Minnesota Electric Rate Case — On Nov.  3, 2008, NSP-Minnesota filed a request with the MPUC to increase Minnesota electric rates by $156 million annually, or 6.05 percent.
The request is based on a 2009 forecast test year, an electric rate base of $4.1 billion, a requested ROE of 11.0 percent and an equity ratio of 52.5 percent.
In December 2008, the MPUC approved an interim rate increase of $132 million, or 5.12 percent, effective Jan.  2, 2009.
The primary difference between interim rate levels approved and NSP-Minnesota’s request of $156 million is due to a previously authorized ROE of 10.54 percent and NSP-Minnesota’s requested ROE of 11.0 percent.
A final decision from the MPUC is expected in the third quarter of 2009.
The following procedural schedule has been established: ?
Staff and intervenor direct testimony on April 7, 2009; ?
NSP-Minnesota rebuttal testimony on May 5, 2009; ?
Staff and intervenor surrebuttal testimony on May 26, 2009; and ?
Evidentiary hearings are scheduled for June 2-9, 2009.
Electric, Purchased Gas and Resource Adjustment Clauses TCR Rider — In November 2006, the MPUC approved a TCR rider pursuant to legislation, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases.
In December 2007, NSP-Minnesota filed adjustments to the TCR rate factors and implemented a rider to recover $18.5 million beginning Jan.  1, 2008.
In March 2008, the MPUC approved the 2008 rider, but required certain procedural changes for future TCR filings if costs are disputed.
On Oct.  30, 2008, NSP-Minnesota submitted its proposed TCR rate factors for proposed recovery in 2009, seeking to recover $14 million beginning Jan.  1, 2009.
A portion of amounts previously collected through the TCR rider prior to 2009 has been included for recovery in the electric rate case described above.
MPUC approval is pending.
RES Rider — In March 2008, the MPUC approved an RES rider to recover the costs for utility-owned projects implemented in compliance with the RES, and the RES rider was implemented on April 1, 2008.
Under the rider, NSP-Minnesota could recover up to approximately $14.5 million in 2008 attributable to the Grand Meadow wind farm, a 100 MW wind project, subject to true-up.
In 2008, NSP-Minnesota submitted the RES rider for recovery of approximately $22 million in 2009 attributable to the Grand Meadow wind farm.
On Feb.  12, 2009, the MPUC
Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities.
The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec.  31, 2008.
Commodity derivatives assets and liabilities assigned to Level 3 consist primarily of FTRs, as well as forwards and options that are either long-term in nature or related to commodities and delivery points with limited observability.
Level 3 commodity derivative assets and liabilities represent approximately 3 percent and 26 percent of total assets and liabilities measured at fair value, respectively, at Dec.  31, 2008.
Determining the fair value of a FTR requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation, and resulting transmission system congestion.
Given the limited observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3.
Level 3 commodity derivatives assets and liabilities include $36.9 million and $13.4 million of estimated fair values, respectively, for FTRs held at Dec.  31, 2008.
Determining the fair value of certain commodity forwards and options can require management to make use of subjective forward price and volatility forecasts for commodities and locations with limited observability, or subjective forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers.
When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3.
Level 3 commodity derivatives assets and liabilities include $2.7 million and $2.9 million of estimated fair values, respectively, for commodity forwards and options held at Dec.  31, 2008.
Nuclear Decommissioning Fund — Nuclear decommissioning fund assets assigned to Level 3 consist of asset-backed and mortgage-backed securities.
To the extent appropriate, observable market inputs are utilized to estimate the fair value of these securities, however, less observable and subjective risk-based adjustments to estimated yield and forecasted prepayments are often significant to these valuations.
Therefore, estimated fair values for all asset-backed and mortgagebacked securities totaling $109.4 million in the nuclear decommissioning fund at Dec.  31, 2008 (approximately 9 percent of total assets measured at fair value), are assigned to Level 3.
Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.
Liquidity and Capital Resources Cash Flows
## Table 3 ##
(a) — See Note 22 to the consolidated financial statements for revision.
Cash provided by operating activities for continuing operations increased by $123 million for 2008 as compared to 2007.
The increase is primarily attributable to changes in other current liabilities due to timing for interest payable and accounts payable and an increase in recoverable gas and electric costs.
This increase was partially offset by changes in working capital activity due to increased inventory, contributions for pension and non-pension postretirement benefits, and an increase in net regulatory assets and liabilities.
The increased inventory reflects the higher cost of natural gas combined with an increase in storage contracts.
The increase in net regulatory assets and liabilities reflects the increase in pension funding obligation, and the decrease in fair value of the investments in the decommissioning fund, partially offset by the decrease in the asset retirement obligation for the extended life of the nuclear facilities.
Cash provided by operating activities for discontinued operations decreased $75 million, primarily due to decreased income taxes received during 2008.
Cash provided by operating activities for continuing operations decreased by $169 million during 2007.
The decrease was primarily due to changes in working capital activity primarily the timing of accounts receivables and unbilled revenues.
The decrease in cash provided by operations was partially offset by the collection of recoverable purchased
## Table 4 ##
Many of the states in which Xcel Energy operates have enacted RESs, which may require significant increases in investment in renewable generation and transmission.
Xcel Energy is able to meet these standards by either purchasing renewable power from an independent party or by owning the assets.
Therefore, these standards may present Xcel Energy with the opportunity to increase its investment in wind generation and transmission assets.
As a result, Xcel Energy’s capital expenditure forecast, as detailed above, may increase due to potential increased investments for renewable generation and transmission assets.
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, regulatory decisions and approvals, 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 restructuring requirements, compliance with future environmental requirements and RPSs to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.
See additional discussion in Item 1 — Electric Utility Operations.
Contractual Obligations and Other Commitments — Xcel Energy has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs.
The following is a summarized table of contractual obligations and other commercial commitments at Dec.  31, 2008.
See additional discussion in the consolidated statements of capitalization and Notes 5, 6, and 17 to the consolidated financial statements.
## Table 5 ##
(a) Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date.
Most of Xcel Energy’s railcar, vehicle and equipment and aircraft leases have these terms.
At Dec.  31, 2008, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $162.1 million.
In addition, at the end of the equipment leases’ terms, each lease must be extended, equipment purchased for the greater of the fair value or unamortized value or equipment sold to a third party with Xcel Energy making up any deficiency between the sales price and the unamortized value.
(b) Included in operating lease payments are $160.3 million, $305.0 million, $292.5 million and $2.3 billion, for the less than 1 year, 1-3 years, 4-5 years and after 5 years categories, respectively, pertaining to nine purchase power agreements that were accounted for as operating leases.
(c) Included in other long-term obligations are tax and interest related to unrecognized tax benefits recorded according to FIN 48.
(d) Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements.
Additionally, the utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations.
Certain contractual purchase obligations are adjusted based on indices.
The effects of price changes are mitigated through cost-of-energy adjustment mechanisms.
(e) Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to approximately $1.5 billion of goods and services through the year 2050, in addition to the amounts disclosed in this table and in the forecasted capital expenditures.

<table><tr><td>Derivative Instrument</td><td>NotionalContractVolumes byYear ofMaturity 2013</td></tr><tr><td>Crude oil and refined products:</td><td></td></tr><tr><td>Swaps – long</td><td>1,300</td></tr><tr><td>Swaps – short</td><td>1,300</td></tr><tr><td>Futures – long</td><td>11,894</td></tr><tr><td>Futures – short</td><td>2,981</td></tr><tr><td>Physical contracts – short</td><td>8,913</td></tr></table>
<table><tr><td> Dividends Per Share</td><td> 2008</td><td> 2007</td><td> 2006</td></tr><tr><td>First quarter</td><td>$0.2300</td><td>$0.2225</td><td>$0.2150</td></tr><tr><td>Second quarter</td><td>0.2375</td><td>0.2300</td><td>0.2225</td></tr><tr><td>Third quarter</td><td>0.2375</td><td>0.2300</td><td>0.2225</td></tr><tr><td>Fourth quarter</td><td>0.2375</td><td>0.2300</td><td>0.2225</td></tr><tr><td></td><td>$0.9425</td><td>$0.9125</td><td>$0.8825</td></tr></table>
<table><tr><td></td><td>Commodity Derivatives, Net</td><td>Nuclear Decommissioning Fund</td></tr><tr><td></td><td colspan="2">(Thousands of Dollars)</td></tr><tr><td>Balance Jan. 1, 2008</td><td>$19,466</td><td>$108,656</td></tr><tr><td>Purchases, issuances, and settlements, net</td><td>-5,981</td><td>12,198</td></tr><tr><td>Transfers out of Level 3</td><td>-3,962</td><td>—</td></tr><tr><td>Gains recognized in earnings</td><td>2,129</td><td>—</td></tr><tr><td>Gains (losses) recognized as regulatory assets and liabilities</td><td>11,569</td><td>-11,431</td></tr><tr><td>Balance Dec. 31, 2008</td><td>$23,221</td><td>$109,423</td></tr></table>
<table><tr><td> </td><td>2008</td><td> 2007<sup>(a)</sup></td><td> 2006</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>$1,683</td><td>$1,560</td><td>$1,729</td></tr><tr><td>Discontinued operations</td><td>-3</td><td>72</td><td>195</td></tr><tr><td>Total</td><td>$1,680</td><td>$1,632</td><td>$1,924</td></tr></table>
<table><tr><td> By Project</td><td> 2009</td><td> 2010</td><td> 2011</td><td> 2012</td></tr><tr><td>Base and other capital expenditures</td><td>$1,305</td><td>$1,500</td><td>$1,520</td><td>$1,665</td></tr><tr><td>Nuclear capacity increases and life extension</td><td>130</td><td>170</td><td>185</td><td>150</td></tr><tr><td>Comanche 3</td><td>130</td><td>15</td><td>—</td><td>—</td></tr><tr><td>NSP-Minnesota wind generation</td><td>110</td><td>420</td><td>370</td><td>—</td></tr><tr><td>CapX 2020</td><td>60</td><td>100</td><td>155</td><td>400</td></tr><tr><td>MERP</td><td>30</td><td>10</td><td>—</td><td>—</td></tr><tr><td>Fort St. Vrain</td><td>25</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Sherco capacity increases</td><td>10</td><td>20</td><td>35</td><td>50</td></tr><tr><td>Infrastructure investment</td><td>—</td><td>65</td><td>85</td><td>85</td></tr><tr><td>Total</td><td>$1,800</td><td>$2,300</td><td>$2,350</td><td>$2,350</td></tr></table>
<table><tr><td> </td><td colspan="5"> Payments Due by Period</td></tr><tr><td> </td><td> Total</td><td> Less than 1 Year</td><td> 1 to 3 Years</td><td> 4 to 5 Years</td><td> After 5 Years</td></tr><tr><td> </td><td colspan="5"> (Thousands of Dollars) </td></tr><tr><td>Long-term debt, principal and interest payments</td><td>$16,855,493</td><td>$1,075,532</td><td>$1,548,736</td><td>$2,128,614</td><td>$12,102,611</td></tr><tr><td>Capital lease obligations</td><td>79,811</td><td>5,984</td><td>11,463</td><td>10,805</td><td>51,559</td></tr><tr><td>Operating leases<sup>(a)(b)</sup></td><td>3,221,077</td><td>186,360</td><td>348,200</td><td>326,399</td><td>2,360,118</td></tr><tr><td>Unconditional purchase obligations</td><td>11,456,886</td><td>2,410,916</td><td>3,003,824</td><td>1,756,451</td><td>4,285,695</td></tr><tr><td>Other long-term obligations — WYCO investment</td><td>46,239</td><td>35,432</td><td>10,807</td><td>—</td><td>—</td></tr><tr><td>Other long-term obligations<sup>(c)</sup></td><td>202,525</td><td>31,768</td><td>64,362</td><td>61,516</td><td>44,879</td></tr><tr><td>Payments to vendors in process</td><td>149,319</td><td>149,319</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Short-term debt</td><td>455,250</td><td>455,250</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total contractual cash obligations<sup>(d)(e)(f)</sup></td><td>$32,466,600</td><td>$4,350,561</td><td>$4,987,392</td><td>$4,283,785</td><td>$18,844,862</td></tr></table>

Question: In the section with largest amount of Other long-term obligations(c), what's the sum of elements (in Thousand)