Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis 3 Palisades plants and related assets to their fair values.
See Note 14 to the financial statements for further discussion of the impairment and related charges.
As a result of the Entergy Louisiana and Entergy Gulf States Louisiana business combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million ($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the terms of the stipulated settlement in the business combination proceeding.
See Note 2 to the financial statements for further discussion of the business combination and customer credits.
Results of operations for 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the $77 million ($47 million net-of-tax) write-off and regulatory charges to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery.
See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.
See Note 2 to the financial statements for further discussion of the Waterford 3 write-off.
Net Revenue Utility Following is an analysis of the change in net revenue comparing 2016 to 2015
## Table 0 ##
The retail electric price variance is primarily due to: ?
an increase in base rates at Entergy Arkansas, as approved by the APSC.
The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016.
The increase includes an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016.
A significant portion of the increase is related to the purchase of Power Block 2 of the Union Power Station; ?
an increase in the purchased power and capacity acquisition cost recovery rider for Entergy New Orleans, as approved by the City Council, effective with the first billing cycle of March 2016, primarily related to the purchase of Power Block 1 of the Union Power Station; ?
an increase in formula rate plan revenues for Entergy Louisiana, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station; and ?
an increase in revenues at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in revenues collected through the storm damage rider.
See Note 2 to the financial statements for further discussion of the rate proceedings.
See Note 14 to the financial statements for discussion of the Union Power Station purchase.
The Louisiana business combination customer credits variance is due to a regulatory liability of $107 million recorded by Entergy in October 2015 as a result of the Entergy Gulf States Louisiana and Entergy Louisiana business
ÿþProduction Expense Components of production expense were as follows:  @T@  N/M Amount is not meaningful.
 See (1) below.
  (1) Other international includes China and unallocated expenses incurred at the corporate level.
  (2) Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other   related lifting costs) and workover and repair expense.
  (3) Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
  Lease Operating Expense Lease operating expense increased in 2011 as compared to 2010 due to the following:  "  higher US sales volumes from the DJ Basin due to ongoing development activities;  "  higher sales volumes in Equatorial Guinea and Israel, as discussed above;  "  higher operating costs associated with the Aseng field which began producing in November 2011; and  "  higher operating costs at the North Sea Dumbarton field related to maintenance at the GP III FPSO;  offset by  "  the sale of certain Oklahoma and Illinois Basin assets in 2010, which had higher lease operating costs.
  Lease operating expense was flat in 2010 as compared with 2009.
 Changes included following:   "  an increase in US sales volumes due to ongoing development activity in DJ Basin, including horizontal   drilling in the Niobrara formation;  "  an increase in US production volumes due to the DJ Basin asset acquisition; and  "  an increase in North Sea lease operating expense due to higher sales volumes;   offset by  "  a decrease in Equatorial Guinea lease operating expense due to the planned shut-down of the Alba field for   facilities maintenance and repair; and  "  the sale of non-core assets in the Mid-Continent and Illinois Basin areas, which had higher lease operating   costs.
   Production and Ad Valorem Tax Expense In the US, the sale of certain non-core Oklahoma and Illinois Basin assets   in 2010 and natural field decline in the Mid-Continent area resulted in a decrease in production and ad valorem taxes   in 2011 as compared with 2010.
 This decrease was offset by higher production and ad valorem taxes in the DJ Basin  due to increased production volumes and higher sales prices.
 Production and ad valorem tax expense for 2011   increased in China as compared with 2010 due to higher sales prices.
  Production and ad valorem tax expense for 2010 increased as compared with 2009 due to higher commodity prices.
  Transportation Expense Transportation expense increased in 2011 as compared with 2010 due to higher sales   volumes in the DJ Basin and new production from our Marcellus Shale producing properties acquired on September   30, 2011, offset by lower transportation expense in the deepwater Gulf of Mexico due to declining production.
  Transportation expense increased in 2010 as compared with 2009 due to an increase in crude oil and condensate   production in the DJ Basin and the use of a new interstate crude oil transportation pipeline system to market   production.

## Table 1 ##
PROVED RESERVES We have historically added reserves through our exploration program, development activities, and acquisition of producing properties.
(See Items 1.  and 2.  Business and Properties).
Changes in proved reserves were as follows:
## Table 2 ##
Revisions Revisions of previous estimates represent changes in previous reserves estimates, either upward (positive) or downward (negative), resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs.
Revisions included the following: ?
changes for the year ended December 31, 2012 included a negative revision of 94 MMBoe due to our decision to terminate the legacy vertical drilling program in Wattenberg and focus on the horizontal development of the Niobrara; net positive revisions of 23 MMBoe, primarily related to better than expected well performance in the Marcellus Shale, the deepwater Gulf of Mexico, and the Aseng field; and negative revisions of 26 MMBoe due to changes in commodity prices; ?
changes for the year ended December 31, 2011 include a negative revision of 28 MMBoe, due primarily to reclassifications of proved undeveloped reserves in Wattenberg that are no longer expected to be developed within five years due to additional shifting of activity from vertical to horizontal development, a negative revision of 10 MMBoe due to reduced activity assumptions for dry gas properties onshore US, as well as other lesser revisions in various other areas related to well performance and changes in commodity prices; and ?
changes for the year ended December 31, 2010 included a positive revision of 43 MMBoe due to higher year-end commodity prices, a negative revision of 30 MMBoe due to reclassifications of proved undeveloped reserves to probable reserves as a result of the SEC’s five year development rule, a negative revision of 7 MMBoe due to a change in the likelihood that the Noa field, offshore Israel, would be pursued for development, and a negative revision of 2 MMBoe due to well performance.
Extensions, Discoveries and Other Additions These are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields.
Extensions, discoveries and other additions included the following: ?
changes for the year ended December 31, 2012 included an increase of 149 MMBoe in the DJ Basin as a result of our decision to focus capital and resources on horizontal development of the Niobrara, 56 MMBoe related to ongoing development of the Marcellus Shale, 7 MMBoe related to the ongoing appraisal of Tamar, and 6 MMBoe for other projects; ?
changes for the year ended December 31, 2011 included increases of 97 MMBoe in the onshore US, primarily associated with horizontal drilling in the DJ Basin and development activities in the Marcellus Shale, 80 MMBoe at Tamar due to appraisal activities, and 3 MMBoe for other projects; and ?
changes for the year ended December 31, 2010 included an increase of 48 MMBoe, which were primarily driven by the execution of low-risk development projects onshore in Wattenberg and the Rocky Mountain area, an increase of 286 MMBoe related to the initial recording of reserves for the Tamar field offshore Israel, and an increase of approximately 27 MMBoe related to the initial recording of reserves for the Alen field, offshore Equatorial Guinea.

<table><tr><td></td><td>Amount (In Millions)</td></tr><tr><td>2015 net revenue</td><td>$5,829</td></tr><tr><td>Retail electric price</td><td>289</td></tr><tr><td>Louisiana business combination customer credits</td><td>107</td></tr><tr><td>Volume/weather</td><td>14</td></tr><tr><td>Louisiana Act 55 financing savings obligation</td><td>-17</td></tr><tr><td>Other</td><td>-43</td></tr><tr><td>2016 net revenue</td><td>$6,179</td></tr></table>
<table><tr><td></td><td>Total perBOE</td><td>Total</td><td>UnitedStates</td><td>EquatorialGuinea</td><td>Israel</td><td>NorthSea</td><td>Other Int'l,Corporate-1</td></tr><tr><td>(millions, except per unit)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Year Ended December 31, 2011</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Lease Operating Expense-2</td><td>$5.07</td><td>$397</td><td>$254</td><td>$53</td><td>$12</td><td>$51</td><td>$27</td></tr><tr><td>Production and Ad Valorem Taxes</td><td>1.86</td><td>146</td><td>102</td><td>-</td><td>-</td><td>-</td><td>44</td></tr><tr><td>Transportation Expense</td><td>0.97</td><td>75</td><td>65</td><td>-</td><td>-</td><td>7</td><td>3</td></tr><tr><td>Total Production Expense-3</td><td>$7.90</td><td>$618</td><td>$421</td><td>$53</td><td>$12</td><td>$58</td><td>$74</td></tr><tr><td>Total Production Expense per BOE</td><td></td><td>$7.90</td><td>$9.85</td><td>$2.64</td><td>$1.16</td><td>$17.17</td><td>N/M</td></tr><tr><td>Year Ended December 31, 2010</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Lease Operating Expense-2</td><td>$4.93</td><td>$376</td><td>$258</td><td>$43</td><td>$9</td><td>$47</td><td>$19</td></tr><tr><td>Production and Ad Valorem Taxes</td><td>1.64</td><td>125</td><td>103</td><td>-</td><td>-</td><td>-</td><td>22</td></tr><tr><td>Transportation Expense</td><td>0.91</td><td>69</td><td>59</td><td>-</td><td>-</td><td>8</td><td>2</td></tr><tr><td>Total Production Expense-3</td><td>$7.48</td><td>$570</td><td>$420</td><td>$43</td><td>$9</td><td>$55</td><td>$43</td></tr><tr><td>Total Production Expense per BOE</td><td></td><td>$7.48</td><td>$9.69</td><td>$2.38</td><td>$1.15</td><td>$13.37</td><td>N/M</td></tr><tr><td>Year Ended December 31, 2009</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Lease Operating Expense-2</td><td>$5.05</td><td>$372</td><td>$258</td><td>$45</td><td>$9</td><td>$43</td><td>$17</td></tr><tr><td>Production and Ad Valorem Taxes</td><td>1.28</td><td>94</td><td>81</td><td>-</td><td>-</td><td>-</td><td>13</td></tr><tr><td>Transportation Expense</td><td>0.80</td><td>59</td><td>52</td><td>-</td><td>-</td><td>4</td><td>3</td></tr><tr><td>Total Production Expense-3</td><td>$7.13</td><td>$525</td><td>$391</td><td>$45</td><td>$9</td><td>$47</td><td>$33</td></tr><tr><td>Total Production Expense per BOE</td><td></td><td>$7.13</td><td>$9.51</td><td>$2.30</td><td>$1.36</td><td>$17.50</td><td>N/M</td></tr></table>
<table><tr><td></td><td colspan="3">Year Ended December 31,</td></tr><tr><td></td><td>2012</td><td>2011</td><td>2010</td></tr><tr><td>(MMBoe)</td><td></td><td></td><td></td></tr><tr><td>Proved Reserves Beginning of Year</td><td>1,209</td><td>1,092</td><td>820</td></tr><tr><td>Revisions of Previous Estimates</td><td>-97</td><td>-50</td><td>5</td></tr><tr><td>Extensions, Discoveries and Other Additions</td><td>218</td><td>180</td><td>360</td></tr><tr><td>Purchase of Minerals in Place</td><td>—</td><td>68</td><td>47</td></tr><tr><td>Sale of Minerals in Place</td><td>-57</td><td>—</td><td>-61</td></tr><tr><td>Production</td><td>-89</td><td>-81</td><td>-79</td></tr><tr><td>Proved Reserves End of Year</td><td>1,184</td><td>1,209</td><td>1,092</td></tr></table>

Question: what portion of the net change in net revenue is due to retail electric price?