curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing.
In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.
The table below discloses the significant inputs to the forward curve used to value these positions.
## Table 0 ##
a) The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
b) Includes current assets for Generation and current liabilities for ComEd of $226 million, related to the fair value of the five-year financial swap contract between Generation and ComEd, which eliminates in consolidation.
c) Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates.
The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
d) The fair values do not include cash collateral held on Level 3 positions of $33 million as of December 31, 2012.
The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted.
The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is volatility.
Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity).
Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option).
Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices.
An increase to the reserves listed above would decrease the fair value of the positions.
An increase to the heat rate or renewable factors would increase the fair value accordingly.
Generally, interrelationships exist between market prices of natural gas and power.
As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning.
For middle market lending the fair value of these loans is determined using a combination of valuations models including cost models, market models and income models.
The valuation estimates are based on valuations of comparable companies, discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfolio company or its assets, considering offers from third parties to buy the portfolio company, its historical and projected financial results, as well as other factors that may impact value.
Significant judgment is required in the applications of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability and relative performance.
Because Generation relies on third party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its’ middle market lending, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation.
This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs.
Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations.
Generation performed procedures to assess the reasonableness of the valuations.
For a sample of its’ middle market lending, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers.
expected generation.
Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity, including purchased power from CENG.
Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including sales to ComEd, PECO and BGE to serve their retail load.
A portion of Generation’s hedging strategy may be implemented through the use of fuel products based on assumed correlations between power and fuel prices, which routinely change in the market.
Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion of Generation’s efforts.
The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop-loss and value-at-risk limits, to manage exposure to market risk.
Additionally, the corporate risk management group and Exelon’s RMC monitor the financial risks of the wholesale and retail power marketing activities.
See Quantitative and Qualitative Disclosures about Market Risk for additional information.
At December 31, 2012, Generation’s short and long-term commitments relating to the purchase of energy and capacity from and to unaffiliated utilities and others were as follows:
## Table 1 ##
(a) Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases.
Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2012, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts.
Expected payments include certain capacity charges which are contingent on plant availability.
(b) Power-Related Purchases include firm REC purchase agreements.
The table excludes renewable energy purchases that are contingent in nature.
(c) Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.
As part of reaching a comprehensive agreement with EDF in October 2010, the existing power purchase agreements with CENG were modified to be unit-contingent through the end of their original term in 2014.
Under these agreements, CENG has the ability to fix the energy price on a forward basis by entering into monthly energy hedge transactions for a portion of the future sale, while any unhedged portions will be provided at market prices by default.
Additionally, beginning in 2015 and continuing to the end of the life of the respective plants, Generation agreed to purchase 50.01% of the available output of CENG’s nuclear plants at market prices.
Generation discloses in the table above commitments to purchase from CENG at fixed prices.
All commitments to purchase from CENG at market prices, which include all purchases subsequent to December 31, 2014, are excluded from the table.
Generation continues to own a 50.01% membership interest in CENG that is accounted for as an equity method investment.
See Note 22 of the Combined Notes to Consolidated Financial Statements for more details on this arrangement.
Capital Expenditures Generation’s business is capital intensive and requires significant investments in nuclear fuel and energy generation assets and in other internal infrastructure projects.
Generation’s estimated capital expenditures for 2013 are as follows:
## Table 2 ##
(a) Includes Generation’s share of the investment in nuclear fuel for the co-owned Salem plant.
(b) Primarily relates to expenditures for the completion of the Antelope Valley development project.
SELECTED FINANCIAL DATA The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon.
This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Financial Information supplement.
## Table 3 ##
(a) The 2012 financial results only include the operations of Constellation and BGE from the date of the merger with Constellation (the Merger), March 12, 2012, through December 31, 2012.
## Table 4 ##
The following table presents electric revenue net of purchased power and fuel expense per MWh of electricity sold during the year ended December 31, 2012 as compared to the same period in 2011 and 2011 as compared to the same period in 2010.
## Table 5 ##
(a) Includes financial results for Constellation business transferred to Generation beginning on March 12, 2012, the date the merger was completed.
(b) Includes sales to PECO of $536 million (7,762 GWh), $508 million (7,041 GWh) and $2,091 million (42,003 GWh) for the years ended December 31, 2012, 2011 and 2010, respectively.
Sales to BGE of $322 million (3,766 GWH) were included for the year ended December 31, 2012.
Excludes compensation under the reliabilitymust-run rate schedule and the financial results of Brandon Shores, H. A.  Wagner, and C. P.  Crane, the generating facilities divested in Q4 2012 as a result of the merger.
(c) Includes sales to ComEd of $162 million (4,152 GWh), $179 million (4,731 GWh) and $288 million (8,218 GWhs) and settlements of the ComEd swap of $627 million, $474 million and $385 million for years ended December 31, 2012, 2011 and 2010, respectively.
(d) Other Regions includes South, West and Canada, which are not considered individually significant.
(e) Revenue net of purchased power and fuel expense per MWh represents the average margin per MWh of electricity sold during the years ended December 31, 2012, 2011 and 2010, respectively, and excludes the mark-to-market impact of Generation’s economic hedging activities.
(f) Excludes retail gas activity, proprietary trading portfolio activity, compensation under the reliability-must-run rate schedule and fuel sales.
Also excludes results from energy efficiency, energy management and demand response, upstream natural gas and the design and construction of renewable energy facilities.
In addition, excludes the financial results of Brandon Shores, H. A.  Wagner, and C. P.  Crane, the generating facilities divested in Q4 2012 as a result of the Exelon and Constellation merger.
Also excludes amortization of intangible assets relating to commodity contracts recorded at fair value at the merger date.
Mid-Atlantic Year Ended December 31, 2012 Compared to Year Ended December 31, 2011.
The increase in revenue net of purchased power and fuel expense in the Mid-Atlantic of $83 million was primarily due to the addition of Constellation in 2012 and higher capacity revenues, partially offset by lower realized power prices and increased nuclear fuel costs.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010.
The $849 million increase in revenue net of purchased power and fuel expense in the Mid-Atlantic was primarily due to increased margins on the volumes previously sold under Generation’s PPA with PECO, which expired on December 31, 2010, partially offset by increased nuclear fuel costs.
Midwest Year Ended December 31, 2012 Compared to Year Ended December 31, 2011.
The decrease in revenue net of purchased power and fuel expense in the Midwest of $549 million was primarily due to lower capacity revenues, increased nuclear fuel costs, and lower realized power prices, partially offset by decreased congestion costs.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010.
The $534 million decrease in revenue net of purchased power and fuel expense in the Midwest was primarily due to decreased realized margins in 2011 for the volumes previously sold by Generation under the 2006 ComEd auction contracts and increased nuclear fuel costs.
These decreases were partially offset by increased capacity revenues, favorable settlements under the ComEd swap and the additional revenue following the acquisition of Exelon Wind in December 2010.
New England Year Ended December 31, 2012 Compared to Year Ended December 31, 2011.
The $187 million increase in revenue net of purchased power and fuel expense in New England was as a result of the Constellation merger.
Prior to the merger, New England was not a significant contributor to revenue net of purchased power and fuel expense at Generation.
New York Year Ended December 31, 2012 Compared to Year Ended December 31, 2011.
The $76 million increase in revenue net of purchased power and fuel expense in New York was as a result of the Constellation merger.
Prior to the merger, New York was not a significant contributor to revenue net of purchased power and fuel expense at Generation.
Movement in Exit Cost LiabilitiesThe movement in exit cost liabilities for PMI was as follows:
## Table 6 ##
Cash payments related to exit costs at PMI were $232 million, $360 million and $21 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Future cash payments for exit costs incurred to date are expected to be approximately $54 million, and will be substantially paid by the end of 2017.
The pre-tax asset impairment and exit costs shown above are primarily a result of the following:The NetherlandsOn April 4, 2014, PMI announced the initiation by its affiliate, Philip Morris Holland B. V.  (“PMH”), of consultations with employee representatives on a proposal to discontinue cigarette production at its factory located in Bergen op Zoom, the Netherlands.
PMH reached an agreement with the trade unions and their members on a social plan and ceased cigarette production on September 1, 2014.
During 2014, total pre-tax asset impairment and exit costs of $489 million were recorded for this program in the European Union segment.
This amount includes employee separation costs of $343 million, asset impairment costs of $139 million and other separation costs of $7 million.
Other Separation Program ChargesPMI recorded other pre-tax separation program charges of $68 million, $41 million and $51 million for the years ended December 31, 2015, 2014 and 2013, respectively.
The 2015 other pre-tax separation program charges primarily related to severance costs for the organizational restructuring in the European Union segment.
The 2014 other pre-tax separation program charges primarily related to severance costs for factory closures in Australia and Canada and the restructuring of the U. S.  leaf purchasing model.
The 2013 pre-tax separation program charges primarily related to the restructuring of global and regional functions based in Switzerland and Australia.
Contract Termination ChargesDuring 2013, PMI recorded exit costs of $258 million related to the termination of distribution agreements in Eastern Europe, Middle East & Africa (due to a new business model in Egypt) and Asia.
Asset Impairment ChargesDuring 2014, PMI recorded other pre-tax asset impairment charges of $5 million related to a factory closure in Canada.

Tables referenced above, in order (Table 0 first):
<table><tr><td> Type of trade</td><td>Fair Valueat December 31, 2012 (d)</td><td> Valuation Technique</td><td> Unobservable Input</td><td> Range</td></tr><tr><td>Mark-to-market derivatives—Economic Hedges (Generation)<sup>(a)</sup></td><td>$473</td><td>Discounted Cash Flow</td><td>Forward power price</td><td>$14 - $79</td></tr><tr><td></td><td></td><td></td><td>Forward gas priceVolatility</td><td>$3.26 - $6.27</td></tr><tr><td></td><td></td><td>Option Model</td><td>percentage</td><td>28% - 132%</td></tr><tr><td>Mark-to-market derivatives—Proprietary trading (Generation)<sup>(a)</sup></td><td>$-6</td><td>Discounted Cash Flow</td><td>Forward power priceVolatility</td><td>$15 - $106</td></tr><tr><td></td><td></td><td>Option Model</td><td>percentage</td><td>16% - 48%</td></tr><tr><td>Mark-to-market derivatives—Transactions with affiliates (Generation and ComEd)<sup>(b)</sup></td><td>$226</td><td>Discounted Cash Flow</td><td>Marketability reserve</td><td>8% - 9%</td></tr><tr><td>Mark-to-market derivatives (ComEd)</td><td>$-67</td><td>Discounted Cash Flow</td><td>Forward heat rate<sup>(c)</sup></td><td>8% - 9.5%</td></tr><tr><td></td><td></td><td></td><td>Marketability reserve</td><td>3.5% - 8.3%</td></tr><tr><td></td><td></td><td></td><td>Renewable factor</td><td>81% - 123%</td></tr></table>
<table><tr><td></td><td> Net Capacity Purchases<sup>(a)</sup></td><td> Power-Related Purchases<sup>(b)</sup></td><td> Transmission Rights Purchases<sup>(c)</sup></td><td> Purchased Energy from CENG</td><td> Total</td></tr><tr><td>2013</td><td>$374</td><td>$95</td><td>$28</td><td>$777</td><td>$1,274</td></tr><tr><td>2014</td><td>353</td><td>69</td><td>26</td><td>516</td><td>964</td></tr><tr><td>2015</td><td>350</td><td>25</td><td>13</td><td>—</td><td>388</td></tr><tr><td>2016</td><td>266</td><td>11</td><td>2</td><td>—</td><td>279</td></tr><tr><td>2017</td><td>203</td><td>3</td><td>2</td><td>—</td><td>208</td></tr><tr><td>Thereafter</td><td>469</td><td>5</td><td>34</td><td>—</td><td>508</td></tr><tr><td>Total</td><td>$2,015</td><td>$208</td><td>$105</td><td>$1,293</td><td>$3,621</td></tr></table>
<table><tr><td>Nuclear fuel<sup>(a)</sup></td><td>$1,000</td></tr><tr><td>Production plant</td><td>1,000</td></tr><tr><td>Renewable energy projects<sup>(b)</sup></td><td>575</td></tr><tr><td>Uprates</td><td>225</td></tr><tr><td>Other</td><td>50</td></tr><tr><td>Total</td><td>$2,850</td></tr></table>
<table><tr><td></td><td colspan="5"> For the Years Ended December 31,</td></tr><tr><td> (In millions, except per share data)</td><td> 2012<sup>(a)</sup></td><td> 2011</td><td> 2010</td><td> 2009</td><td> 2008</td></tr><tr><td> Statement of Operations data:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$23,489</td><td>$19,063</td><td>$18,644</td><td>$17,318</td><td>$18,859</td></tr><tr><td>Operating income</td><td>2,380</td><td>4,479</td><td>4,726</td><td>4,750</td><td>5,299</td></tr><tr><td>Income from continuing operations</td><td>1,171</td><td>2,499</td><td>2,563</td><td>2,706</td><td>2,717</td></tr><tr><td>Income from discontinued operations</td><td>—</td><td>—</td><td>—</td><td>1</td><td>20</td></tr><tr><td>Net income</td><td>1,171</td><td>2,499</td><td>2,563</td><td>2,707</td><td>2,737</td></tr><tr><td>Earnings per average common share (diluted):</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Income from continuing operations</td><td>$1.42</td><td>$3.75</td><td>$3.87</td><td>$4.09</td><td>$4.10</td></tr><tr><td>Income from discontinued operations</td><td>—</td><td>—</td><td>—</td><td>—</td><td>0.03</td></tr><tr><td>Net income</td><td>$1.42</td><td>$3.75</td><td>$3.87</td><td>$4.09</td><td>$4.13</td></tr><tr><td>Dividends per common share</td><td>$2.10</td><td>$2.10</td><td>$2.10</td><td>$2.10</td><td>$2.03</td></tr><tr><td>Average shares of common stock outstanding—diluted</td><td>819</td><td>665</td><td>663</td><td>662</td><td>662</td></tr></table>
<table><tr><td></td><td colspan="5"> December 31,</td></tr><tr><td> (In millions)</td><td> 2012</td><td> 2011</td><td> 2010</td><td> 2009</td><td> 2008</td></tr><tr><td> Balance Sheet data:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$10,133</td><td>$5,713</td><td>$6,398</td><td>$5,441</td><td>$5,130</td></tr><tr><td>Property, plant and equipment, net</td><td>45,186</td><td>32,570</td><td>29,941</td><td>27,341</td><td>25,813</td></tr><tr><td>Noncurrent regulatory assets</td><td>6,497</td><td>4,518</td><td>4,140</td><td>4,872</td><td>5,940</td></tr><tr><td>Goodwill</td><td>2,625</td><td>2,625</td><td>2,625</td><td>2,625</td><td>2,625</td></tr><tr><td>Other deferred debits and other assets</td><td>14,113</td><td>9,569</td><td>9,136</td><td>8,901</td><td>8,038</td></tr><tr><td>Total assets</td><td>$78,554</td><td>$54,995</td><td>$52,240</td><td>$49,180</td><td>$47,546</td></tr><tr><td>Current liabilities</td><td>$7,784</td><td>$5,134</td><td>$4,240</td><td>$4,238</td><td>$3,811</td></tr><tr><td>Long-term debt, including long-term debt to financing trusts</td><td>18,346</td><td>12,189</td><td>12,004</td><td>11,385</td><td>12,592</td></tr><tr><td>Noncurrent regulatory liabilities</td><td>3,981</td><td>3,627</td><td>3,555</td><td>3,492</td><td>2,520</td></tr><tr><td>Other deferred credits and other liabilities</td><td>26,626</td><td>19,570</td><td>18,791</td><td>17,338</td><td>17,489</td></tr><tr><td>Preferred securities of subsidiary</td><td>87</td><td>87</td><td>87</td><td>87</td><td>87</td></tr><tr><td>Noncontrolling interest</td><td>106</td><td>3</td><td>3</td><td>—</td><td>—</td></tr><tr><td>BGE preference stock not subject to mandatory redemption</td><td>193</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Shareholders’ equity</td><td>21,431</td><td>14,385</td><td>13,560</td><td>12,640</td><td>11,047</td></tr><tr><td>Total liabilities and shareholders’ equity</td><td>$78,554</td><td>$54,995</td><td>$52,240</td><td>$49,180</td><td>$47,546</td></tr></table>
<table><tr><td> $/MWh</td><td> 2012<sup>(a)</sup></td><td>2011</td><td>2012 vs. 2011 % Change</td><td>2010</td><td>2011 vs. 2010 % Change</td></tr><tr><td>Mid-Atlantic<sup>(b)</sup></td><td>$44.60</td><td>$58.00</td><td>-23.1%</td><td>$42.48</td><td>36.5%</td></tr><tr><td>Midwest<sup>(c)</sup></td><td>29.02</td><td>35.99</td><td>-19.4%</td><td>40.98</td><td>-12.2%</td></tr><tr><td>New England</td><td>10.19</td><td>n.m.</td><td>n.m.</td><td>—</td><td>n.m.</td></tr><tr><td>New York</td><td>6.63</td><td>n.m.</td><td>n.m.</td><td>—</td><td>n.m.</td></tr><tr><td>ERCOT</td><td>13.74</td><td>8.78</td><td>56.5%</td><td>-6.24</td><td>n.m.</td></tr><tr><td>Other Regions<sup>(d)</sup></td><td>5.64</td><td>-3.56</td><td>n.m.</td><td>-23.97</td><td>85.1%</td></tr><tr><td>Electric revenue net of purchased power and fuel expense per MWh<sup>(e)(f)</sup></td><td>$27.45</td><td>$41.07</td><td>-33.2%</td><td>$37.62</td><td>9.2%</td></tr></table>
<table><tr><td>Liability balance, January 1, 2014</td><td>$308</td></tr><tr><td>Charges, net</td><td>391</td></tr><tr><td>Cash spent</td><td>-360</td></tr><tr><td>Currency/other</td><td>-69</td></tr><tr><td>Liability balance, December 31, 2014</td><td>$270</td></tr><tr><td>Charges, net</td><td>68</td></tr><tr><td>Cash spent</td><td>-232</td></tr><tr><td>Currency/other</td><td>-52</td></tr><tr><td>Liability balance, December 31, 2015</td><td>$54</td></tr></table>

Question: what was the difference in cash payments related to exit costs at pmi from 2013 to 2014 in millions?
Answer: 339
Reasoning program: subtract(360,21)