ENTERGY TEXAS, INC.  AND SUBSIDIARIES MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations Net Income 2016 Compared to 2015 Net income increased $37.9 million primarily due to lower other operation and maintenance expenses, the asset write-off of its receivable associated with the Spindletop gas storage facility in 2015, and higher net revenue.2015 Compared to 2014 Net income decreased $5.2 million primarily due to the asset write-off of its receivable associated with the Spindletop gas storage facility and higher other operation and maintenance expenses, partially offset by higher net revenue and a lower effective tax rate.
Net Revenue 2016 Compared to 2015 Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges.
Following is an analysis of the change in net revenue comparing 2016 to 2015.
## Table 0 ##
The reserve equalization variance is primarily due to a reduction in reserve equalization expense primarily due to changes in the Entergy System generation mix compared to the same period in 2015 as a result of the execution of a new purchased power agreement and Entergy Mississippi’s exit from the System Agreement, each in November 2015, and Entergy Texas’s exit from the System Agreement in August 2016.
See Note 2 to the financial statements for a discussion of the System Agreement.
The purchased power capacity variance is primarily due to decreased expenses due to the termination of the purchased power agreements between Entergy Louisiana and Entergy Texas in August 2016, as well as capacity cost changes for ongoing purchased power capacity contracts.
The transmission revenue variance is primarily due to an increase in Attachment O rates charged by MISO to transmission customers and a settlement of Attachment O rates previously billed to transmission customers by MISO.
Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well.
Undeveloped acreage is comprised of leased acres with defined remaining terms and not within an area spaced by or assignable to a productive well.
A gross acre is any leased acre in which a working interest is owned.
A net acre is comprised of the total of the owned working interest(s) in a gross acre expressed in a fractional format.
Future Acreage Expirations If production is not established or we take no other action to extend the terms of the leases, licenses, or concessions, undeveloped acreage will expire over the next three years as follows:
## Table 1 ##
(1) Represents acreage that will expire if no further action is taken to extend.
We currently intend to extend the leases prior to expiration in accordance with license terms.
(2) The acreage in Cameroon is comprised of our Tilapia PSC and our YoYo mining concession.
Per our Tilapia PSC, we are required to drill two wells in the initial exploratory phase of our agreement which ends in July of 2012 to be eligible for an initial two year renewal period.
Presently, we have drilled one well and we intend to drill the second well required under the agreement in the first half of 2012.
At the end of the renewal period, ending in July 2014, there is a relinquishment requirement for 50% (479,000 gross acres) of the Tilapia acreage.
Pursuant to the YoYo mining concession, if development is not commenced by December 2014, we will be required to relinquish all 168,000 acres we hold under the mining concession.
During 2011, the US Bureau of Safety and Environmental Enforcement (BSEE) granted one year extensions to the original terms of 26 of our deepwater Gulf of Mexico leases.
To be eligible for an extension, each lease had to meet the following three criteria: no oil and gas production on the lease as of May 15, 2011, the lease includes water depths in excess of 500 feet, and the lease is scheduled to expire on or before December 31, 2015.
The extensions were granted to allow more time to drill on offshore leases following the Deepwater Moratorium.
Drilling Activity The results of crude oil and natural gas wells drilled and completed for each of the last three years were as follows:
## Table 2 ##
(1) Includes successful exploratory wells drilled but not yet producing.
Indirect Consequences of Regulation or Business Trends We believe there are both risks and opportunities arising from the global response to potential climate change.
See Items 1.  and 2.  Business and Properties – Regulations and the following risk factors listed in Item 1A.
Risk Factors – ?
We are subject to increasing governmental regulations and environmental requirements that may cause us to incur substantial incremental costs; and ?
The adoption of GHG emission or other environmental legislation could result in additional operating costs, create delays in our obtaining air pollution permits for new or modified facilities, and reduce demand for the crude oil and natural gas we produce.
In terms of opportunities, the regulation of GHGs and introduction of formal technology incentives, such as enhanced oil recovery, carbon sequestration and low carbon fuel standards, could benefit us in a variety of ways.
First, approximately 61% of our 2011 total sales volume were natural gas.
GHG emissions regulation could reduce the demand for the crude oil we produce.
At the same time, the burning of natural gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal.
Therefore, the use of natural gas may increase should the use of other fossil fuels decrease due to GHG emissions regulation.
The 2011 incident at the Fukushima nuclear plant in Japan has re-opened debate about the future of nuclear power as an alternative to fossil fuels, and public concern about nuclear safety has been heightened.
In response, Germany, Japan, and other nations have announced future shutdowns of nuclear plants and/or moratoria on future nuclear plant construction, resulting in increased demand for alternate fuel sources, including natural gas, for power generation.
Furthermore, should renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply.
Second, market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could benefit us through the potential to obtain GHG allowances or offsets from or government incentives for the sequestration of carbon dioxide.
Finally, as the EPA’s new GHG standards for light duty vehicles became effective in 2011, natural gas may prove to be a more attractive transportation fuel.
This may increase the market demand for natural gas.
Physical Impacts of Climate Change on our Costs and Operations There has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels.
Extreme weather conditions limit our production and increase our costs, and damage resulting from extreme weather may not be fully insured.
However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations, particularly our offshore operations and our onshore US operations in the DJ Basin and Marcellus Shale.
See Item 1A.
Risk Factors – The insurance we carry is insufficient to cover all of the risks we face, which could result in significant financial exposure.
Recently Issued Accounting Standards Update See Item 8.
Financial Statements and Supplementary Data – Note 1.
Summary of Significant Account Policies.
RESULTS OF OPERATIONS Selected financial information is as follows:
## Table 3 ##
If the realized gains and losses on commodity derivative instruments, which are included in (gain) loss on commodity derivative instruments in our consolidated statements of operations, had been included in oil and gas revenues, the effect on average realized prices would have been as follows:
## Table 4 ##
Crude Oil and Condensate Sales Revenues from crude oil and condensate sales increased by a net $578 million, or 32%, in 2011 as compared with 2010 due to the following: ?
a 32% increase in total consolidated average realized prices due to increased demand resulting from the global economic recovery; ?
higher sales volumes in the DJ Basin, including a 21% increase in Wattenberg sales volumes, attributable to the continued acceleration of our horizontal Niobrara project; and ?
higher sales volumes in Equatorial Guinea due to a higher number of liftings from our Alba field and due to the commencement of oil production at Aseng which impacted our sales volumes by approximately 9 MBbl/d in the fourth quarter; partially offset by ?
a decrease in onshore US volumes due to the divestment of non-core oil assets; ?
a decrease in deepwater Gulf of Mexico volumes due to natural field decline and third party downstream facility constraints; and ?
a decrease in North Sea volumes due to downtime in the Dumbarton field for GP III FPSO maintenance.
Revenues from crude oil and condensate sales increased by a net $534 million, or 42%, in 2010 as compared with 2009 due to the following: ?
a 37% increase in total consolidated average realized prices due to increased demand resulting from the global economic recovery; ?
increased production due to ongoing development activity in the DJ Basin, including the horizontal Niobrara drilling program; ?
additional production from the DJ Basin asset acquisition in March 2010; ?
crude oil production from a Swordfish side track oil well that commenced production first quarter 2010; ?
renewed production from Ticonderoga in the deepwater Gulf of Mexico which was off-line first quarter 2009 as a result of hurricane damage to third-party processing and pipeline facilities; and ?
an increase in North Sea sales volumes primarily as a result of increased deliverability at the Dumbarton complex, which included the addition of two Lochranza wells in 2010; partially offset by ?
a decrease in onshore US volumes due to the divestment of non-core crude oil producing assets; ?
a decrease in deepwater Gulf of Mexico volumes due to natural field decline and third party downstream facility constraints; ?
a decrease in onshore US volumes due to natural field decline in the Mid-Continent and Gulf Coast areas; and ?
a decrease in Equatorial Guinea sales volumes due to the planned shut-down of the Alba field for facilities maintenance and repair during 2010 and the timing of liftings.
Revenues from crude oil and condensate sales included deferred losses of $19 million in 2010 and $58 million in 2009 reclassified from AOCL related to commodity derivative instruments previously accounted for as cash flow hedges.
As of December 31, 2010, there were no further amounts related to commodity derivative instruments remaining to be reclassified from AOCL to crude oil revenues.
See Item 8.
Financial Statements and Supplementary Data – Note 10.
Derivative Instruments and Hedging Activities.
Investing Activities The primary use of cash in investing activities is for capital spending, which may be offset by proceeds from property sales.
Capital spending, on a cash basis, totaled $3.2 billion in 2011, including $596 million spent on the Marcellus Shale asset acquisition, representing an increase of $847 million as compared with 2010.
A significant portion of the spending was related to our major development projects.
We received $77 million total proceeds from asset divestitures.
Capital spending, on a cash basis, totaled $2.3 billion in 2010, including $458 million spent on the DJ Basin asset acquisition, representing an increase of $1.1 billion as compared with 2009.
A significant portion of the spending was related to our major development projects.
We received $564 million total proceeds from asset divestitures.
In 2009, our capital spending including acquisitions, totaled $1.3 billion.
We received net proceeds from property sales of $3 million.
Financing Activities Net cash provided by financing activities was $1.3 billion in 2011.
Funds were provided by net cash proceeds from the issuance of $850 million 6% senior notes ($836 million) and the issuance of $1.0 billion 4.15% senior notes ($992 million).
Also, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($53 million).
Funds were used for net repayments under our revolving credit facility ($350 million).
We also used cash to settle an interest rate lock ($40 million), pay dividends on our common stock ($143 million), repurchase shares of our common stock ($17 million), and other ($14 million).
In 2010, net cash of $100 million was used in financing activities.
Funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($72 million).
Funds were used for net repayments under our revolving credit facility ($32 million).
We paid cash dividends on our common stock ($127 million), and repurchased shares of our common stock ($13 million).
In 2009, net cash of $369 million was used in financing activities.
We received $989 million net proceeds from the issuance of our 8?% senior notes.
Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($22 million).
We made net repayments of amounts outstanding under our revolving credit facility ($1.2 billion), repaid an installment note ($25 million), and repurchased a portion of our 7?% Senior Debentures due August 1, 2097 ($4 million).
We also paid cash dividends on our common stock ($126 million) and repurchased shares of our common stock ($1 million).
Acquisition, Capital and Other Exploration Expenditures Acquisition, Capital and Other Exploration Expenditures Information for investing activities (on an accrual basis) is as follows:

Tables referenced above, in order (Table 0 first):
<table><tr><td></td><td>Amount (In Millions)</td></tr><tr><td>2015 net revenue</td><td>$637.2</td></tr><tr><td>Reserve equalization</td><td>14.3</td></tr><tr><td>Purchased power capacity</td><td>12.4</td></tr><tr><td>Transmission revenue</td><td>7.0</td></tr><tr><td>Retail electric price</td><td>5.4</td></tr><tr><td>Net wholesale</td><td>-27.8</td></tr><tr><td>Other</td><td>-4.3</td></tr><tr><td>2016 net revenue</td><td>$644.2</td></tr></table>
<table><tr><td></td><td colspan="6">Year Ended December 31,</td></tr><tr><td></td><td colspan="2">2012</td><td colspan="2">2013</td><td colspan="2">2014</td></tr><tr><td></td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td></tr><tr><td>(thousands of acres)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Onshore US</td><td>87</td><td>59</td><td>216</td><td>146</td><td>120</td><td>84</td></tr><tr><td>Deepwater Gulf of Mexico</td><td>40</td><td>21</td><td>37</td><td>17</td><td>29</td><td>20</td></tr><tr><td>Equatorial Guinea</td><td>-</td><td>-</td><td>307</td><td>137</td><td>-</td><td>-</td></tr><tr><td>Israel-1</td><td>198</td><td>93</td><td>1,209</td><td>537</td><td>-</td><td>-</td></tr><tr><td>Cameroon-2</td><td>-</td><td>-</td><td>-</td><td>-</td><td>647</td><td>323</td></tr><tr><td>Total</td><td>325</td><td>173</td><td>1,769</td><td>837</td><td>796</td><td>427</td></tr></table>
<table><tr><td></td><td colspan="3">Net Exploratory Wells</td><td colspan="3">Net Development Wells</td><td></td></tr><tr><td></td><td>Productive</td><td>Dry</td><td>Total</td><td>Productive</td><td>Dry</td><td>Total</td><td>Total</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>United States-1</td><td>9.6</td><td>3.7</td><td>13.3</td><td>641.2</td><td>4.0</td><td>645.2</td><td>658.5</td></tr><tr><td>Equatorial Guinea-1</td><td>0.5</td><td>-</td><td>0.5</td><td>0.5</td><td>-</td><td>0.5</td><td>1.0</td></tr><tr><td>Cameroon</td><td>-</td><td>0.5</td><td>0.5</td><td>-</td><td>-</td><td>-</td><td>0.5</td></tr><tr><td>Senegal/Guinea-Bissau</td><td>-</td><td>0.3</td><td>0.3</td><td>-</td><td>-</td><td>-</td><td>0.3</td></tr><tr><td>Israel-1</td><td>0.8</td><td>-</td><td>0.8</td><td>-</td><td>-</td><td>-</td><td>0.8</td></tr><tr><td>Cyprus-1</td><td>0.7</td><td>-</td><td>0.7</td><td>-</td><td>-</td><td>-</td><td>0.7</td></tr><tr><td>China</td><td>-</td><td>-</td><td>-</td><td>2.9</td><td>-</td><td>2.9</td><td>2.9</td></tr><tr><td>Total</td><td>11.6</td><td>4.5</td><td>16.1</td><td>644.6</td><td>4.0</td><td>648.6</td><td>664.7</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>United States-1</td><td>4.8</td><td>1.9</td><td>6.7</td><td>510.6</td><td>1.0</td><td>511.6</td><td>518.3</td></tr><tr><td>Equatorial Guinea-1</td><td>-</td><td>-</td><td>-</td><td>2.0</td><td>-</td><td>2.0</td><td>2.0</td></tr><tr><td>Israel-1</td><td>0.4</td><td>-</td><td>0.4</td><td>1.0</td><td>-</td><td>1.0</td><td>1.4</td></tr><tr><td>North Sea</td><td>-</td><td>-</td><td>-</td><td>0.6</td><td>-</td><td>0.6</td><td>0.6</td></tr><tr><td>China</td><td>-</td><td>-</td><td>-</td><td>2.3</td><td>-</td><td>2.3</td><td>2.3</td></tr><tr><td>Total</td><td>5.2</td><td>1.9</td><td>7.1</td><td>516.5</td><td>1.0</td><td>517.5</td><td>524.6</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>United States-1</td><td>4.1</td><td>1.6</td><td>5.7</td><td>532.3</td><td>2.0</td><td>534.3</td><td>540.0</td></tr><tr><td>Equatorial Guinea-1</td><td>0.5</td><td>-</td><td>0.5</td><td>-</td><td>-</td><td>-</td><td>0.5</td></tr><tr><td>Israel-1</td><td>1.1</td><td>-</td><td>1.1</td><td>-</td><td>-</td><td>-</td><td>1.1</td></tr><tr><td>North Sea</td><td>-</td><td>-</td><td>-</td><td>1.0</td><td>-</td><td>1.0</td><td>1.0</td></tr><tr><td>China</td><td>-</td><td>-</td><td>-</td><td>0.6</td><td>-</td><td>0.6</td><td>0.6</td></tr><tr><td>Total</td><td>5.7</td><td>1.6</td><td>7.3</td><td>533.9</td><td>2.0</td><td>535.9</td><td>543.2</td></tr></table>
<table><tr><td></td><td colspan="3">Year Ended December 31,</td></tr><tr><td></td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>(millions, except per share)</td><td></td><td></td><td></td></tr><tr><td>Total Revenues</td><td>$3,763</td><td>$3,022</td><td>$2,313</td></tr><tr><td>Total Operating Expenses</td><td>3,023</td><td>2,070</td><td>2,371</td></tr><tr><td>Operating Income (Loss)</td><td>740</td><td>952</td><td>-58</td></tr><tr><td>Total Other (Income) Expense</td><td>25</td><td>-79</td><td>206</td></tr><tr><td>Income (Loss) Before Income Taxes</td><td>715</td><td>1,031</td><td>-264</td></tr><tr><td>Net Income (Loss)</td><td>453</td><td>725</td><td>-131</td></tr><tr><td>Earnings (Loss) Per Share</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$2.57</td><td>$4.15</td><td>$-0.75</td></tr><tr><td>Diluted</td><td>2.54</td><td>4.10</td><td>-0.75</td></tr></table>
<table><tr><td></td><td colspan="6">Commodity Price Increase (Decrease) Year Ended December 31,</td></tr><tr><td></td><td colspan="2">2011</td><td colspan="2">2010</td><td colspan="2">2009</td></tr><tr><td></td><td>Crude Oil & Condensate</td><td>NaturalGas</td><td>Crude Oil & Condensate</td><td>NaturalGas</td><td>Crude Oil &Condensate</td><td>NaturalGas</td></tr><tr><td></td><td>(Per Bbl)</td><td>(Per Mcf)</td><td>(Per Bbl)</td><td>(Per Mcf)</td><td>(Per Bbl)</td><td>(Per Mcf)</td></tr><tr><td>United States</td><td>$-3.22</td><td>$0.77</td><td>$-0.65</td><td>$0.76</td><td>$12.26</td><td>$1.73</td></tr><tr><td>Equatorial Guinea</td><td>-</td><td>-</td><td>-3.41</td><td>-</td><td>15.36</td><td>-</td></tr><tr><td>Total Consolidated Operations</td><td>-1.89</td><td>0.37</td><td>-1.00</td><td>0.40</td><td>10.86</td><td>0.91</td></tr><tr><td>Total</td><td>-1.84</td><td>0.37</td><td>-0.97</td><td>0.40</td><td>10.55</td><td>0.91</td></tr></table>

Question: In the year with the greatest proportion of Onshore US, what is the proportion of Onshore US to the total?
Answer: 0.1221
Reasoning program: divide(216,1769)