MARATHON OIL CORPORATION Notes to Consolidated Financial Statements (g) This obligation relates to a lease of equipment at United States Steel’s Clairton Works cokemaking facility in Pennsylvania.
We are the primary obligor under this lease.
Under the Financial Matters Agreement, United States Steel has assumed responsibility for all obligations under this lease.
This lease is an amortizing financing with a final maturity of 2012.
(h) These notes are senior secured notes of Marathon Oil Canada Corporation.
The notes are secured by substantially all of Marathon Oil Canada Corporation’s assets.
In January 2008, we provided a full and unconditional guarantee covering the payment of all principal and interest due under the senior notes.
(i) These obligations as of December 31, 2009 include $36 million related to assets under construction at that date for which a capital lease will commence upon completion of construction.
The amounts currently reported are based upon the percent of construction completed as of December 31, 2009 and therefore do not reflect future minimum lease obligations of $164 million related to the asset.
(j) Payments of long-term debt for the years 2010 - 2014 are $102 million, $246 million, $1,492 million, $287 million and $802 million.
United Steel is due to pay $17 million in 2010, $161 million in 2011, $19 million in 2012, and $11 for year 2014.
(k) In the event of a change in control, as defined in the related agreements, debt obligations totaling $662 million at December 31, 2009, may be declared immediately due and payable.
(l) See Note 16 for information on interest rate swaps.20.
Asset Retirement Obligations The following summarizes the changes in asset retirement obligations:
## Table 0 ##
(a) Includes asset retirement obligation of $3 and $2 million classified as short-term at December 31, 2009, and 2008.
Seasonality and Price Volatility Annual and quarterly operating results of the Company's wholesale power generation segments can be significantly affected by weather and energy commodity price volatility.
Significant other events, such as the demand for natural gas, interruptions in fuel supply infrastructure and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility.
The preceding factors related to seasonality and price volatility are fairly uniform across the Company's wholesale generation business segments.
The sale of electric power to retail customers is also a seasonal business with the demand for power generally peaking during the summer months.
As a result, net working capital requirements for the Company's retail operations generally increase during summer months along with the higher revenues, and then decline during off-peak months.
Weather may impact operating results and extreme weather conditions could materially affect results of operations.
The rates charged to retail customers may be impacted by fluctuations in total power prices and market dynamics like the price of natural gas, transmission constraints, competitor actions, and changes in market heat rates.
Operational Statistics The following are industry statistics for the Company's fossil and nuclear plants, as defined by the NERC, and are more fully described below: Annual Equivalent Availability Factor, or EAF — Measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account.
Net Heat Rate — The net heat rate represents the total amount of fuel in BTU required to generate one net kWh provided.
Net Capacity Factor — The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period.
The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation.
The tables below present these performance metrics for the Company's U. S.  power generation portfolio, including leased facilities and those accounted for through equity method investments, for the years ended December 31, 2015, and 2014:
## Table 1 ##
Year Ended December 31, 2014
## Table 2 ##
(a) NRG Yield includes thermal generation.
Regional Regulatory Developments NRG is affected by rule/tariff changes that occur in the ISO regions.
For further discussion on regulatory developments see Item 15 — Note 23, Regulatory Matters, to the Consolidated Financial Statements.
East Region PJM PJM Auction Results — On August 21, 2015, PJM announced the results of its 2018/2019 Base Residual Auction, officially integrating the new Capacity Performance product into the market.
NRG cleared approximately 13,388 MW of Capacity Performance product and 784 MW of Base Capacity product in the 2018/2019 Base Residual Auction.
NRG’s expected capacity revenues from the 2018/2019 Base Residual Auction are approximately $900 million.
PJM announced the results of its Transitional Capacity Auctions for the 2016/2017 and 2017/2018 delivery years, respectively, on August 31, 2015, and September 9, 2015.
NRG cleared approximately 3,900 MW of Capacity Performance product in the 2016/2017 Transactional Capacity Auction, and 9,700 MW of Capacity Performance product in the 2017/2018 Transitional Capacity Auction.
NRG expects an approximately $425 million increase in PJM capacity revenue from 2016/2017 to 2018/2019 due to the Capacity Performance product.
The table below provides a detailed description of NRG’s 2018/2019 Base Residual Auction results:
## Table 3 ##
(1) Includes imports.
Does not include capacity sold by NRG Curtailment Specialists.
Capacity Performance Rehearings — On June 9, 2015, FERC approved changes to PJM’s capacity market.
Major elements of the approved changes to the Capacity Performance framework include the calculation of the bid cap, elimination of the 2.5% holdback for short lead-time resources, and substantial performance penalties on Capacity Performance resources that do not perform in real time during specific periods of high demand.
The rules mandate that underperformance penalties be paid to units that over perform during those periods of high demand.
NRG’s actual revenues will be the combination of the revenues based on the cleared auction MW plus the net of any over and under performance of NRG's fleet.
On July 9, 2015, multiple parties, including NRG, filed requests for rehearings at FERC regarding the framework of the new annual capacity auctions.
Rehearing is pending.
In addition, multiple parties sought clarification on whether demand resources could participate in the Capacity Performance Transition Auctions.
On July 22, 2015, FERC issued an order allowing demand response and energy efficiency resources to participate in the Capacity Performance Transition Auctions.
Rehearing is pending.
Capacity Replacement — On March 10, 2014, PJM filed at FERC to limit speculation in the forward capacity auction.
Specifically, PJM proposed tariff changes that are designed to ensure that only capacity resources that are reasonably expected to be provided as a physical resource by the start of the delivery year can participate in the Base Residual Auction.
These changes include the addition of a replacement capacity adjustment charge that is intended to remove the incentive to profit from replacing capacity commitments, an increase in deficiency penalties for non-performance, and a reduction in the number of incremental auctions from three to one.
On May 9, 2014, FERC rejected PJM’s proposed changes to address replacement capacity and incremental auction design, but established a Section 206 proceeding and technical conference to find a just-and-reasonable outcome.
On August 18, 2014, PJM requested that FERC defer further action in the proceeding.
Since the request, FERC has taken no action.
The Section 206 proceeding and technical conference could have a material impact on future PJM capacity prices.
The following table provides the details of NRG's operating revenues:

<table><tr><td><i>(In millions)</i></td><td>2009</td><td>2008</td></tr><tr><td>Asset retirement obligations as of January 1</td><td>$965</td><td>$1,134</td></tr><tr><td>Liabilities incurred, including acquisitions</td><td>14</td><td>30</td></tr><tr><td>Liabilities settled</td><td>-65</td><td>-94</td></tr><tr><td>Accretion expense (included in depreciation, depletion and amortization)</td><td>64</td><td>66</td></tr><tr><td>Revisions to previous estimates</td><td>124</td><td>24</td></tr><tr><td>Held for sale</td><td>-</td><td>-195</td></tr><tr><td>Asset retirement obligations as of December 31<sup>(a)</sup></td><td>$1,102</td><td>$965</td></tr></table>
<table><tr><td></td><td colspan="5">Year Ended December 31, 2015</td></tr><tr><td></td><td></td><td></td><td colspan="3">Fossil and Nuclear Plants</td></tr><tr><td></td><td>Net OwnedCapacity (MW)</td><td>Net Generation (MWh)</td><td>Annual Equivalent Availability Factor</td><td>Average Net Heat Rate BTU/kWh</td><td>Net CapacityFactor</td></tr><tr><td></td><td colspan="5">(In thousands of MWh)</td></tr><tr><td>NRG Business</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gulf Coast</td><td>14,941</td><td>57,679</td><td>85.7%</td><td>9,651</td><td>44.4%</td></tr><tr><td>East</td><td>23,579</td><td>46,289</td><td>84.0</td><td>10,477</td><td>21.6</td></tr><tr><td>West</td><td>6,085</td><td>4,542</td><td>86.4</td><td>9,189</td><td>8.1</td></tr><tr><td>NRG Renew</td><td>1,966</td><td>4,461</td><td>95.0</td><td>—</td><td>39.4</td></tr><tr><td>NRG Yield<sup>(a)</sup></td><td>4,565</td><td>10,471</td><td>95.7</td><td>8,651</td><td>22.9</td></tr></table>
<table><tr><td></td><td colspan="5">Year Ended December 31, 2014</td></tr><tr><td></td><td></td><td></td><td colspan="3">Fossil and Nuclear Plants</td></tr><tr><td></td><td>Net OwnedCapacity (MW)</td><td>Net Generation (MWh)</td><td>Annual Equivalent Availability Factor</td><td>Average Net Heat Rate BTU/kWh</td><td>Net CapacityFactor</td></tr><tr><td></td><td colspan="5">(In thousands of MWh)</td></tr><tr><td>NRG Business</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gulf Coast</td><td>15,412</td><td>59,871</td><td>86.6%</td><td>9,694</td><td>44.6%</td></tr><tr><td>East</td><td>24,607</td><td>51,192</td><td>81.6</td><td>10,367</td><td>24.0</td></tr><tr><td>West</td><td>7,132</td><td>4,241</td><td>91.2</td><td>9,132</td><td>7.1</td></tr><tr><td>NRG Renew</td><td>1,911</td><td>4,026</td><td>—</td><td>—</td><td>—</td></tr><tr><td>NRG Yield<sup>(a)</sup></td><td>4,367</td><td>8,373</td><td>95.5</td><td>8,794</td><td>23.6</td></tr></table>
<table><tr><td></td><td colspan="2">Base Capacity Product</td><td colspan="2">Capacity Performance Product</td></tr><tr><td>Zone</td><td>Cleared Capacity (MW)<sup>(1)</sup></td><td>Price($/MW-day)</td><td>Cleared Capacity (MW)<sup>(1)</sup></td><td>Price($/MW-day)</td></tr><tr><td>COMED</td><td>221</td><td>$200.21</td><td>4,088</td><td>$215.00</td></tr><tr><td>EMAAC</td><td>189</td><td>$210.63</td><td>981</td><td>$225.42</td></tr><tr><td>MAAC</td><td>68</td><td>$149.98</td><td>6,618</td><td>$164.77</td></tr><tr><td>RTO</td><td>306</td><td>$149.98</td><td>1,701</td><td>$164.77</td></tr><tr><td>Total</td><td>784</td><td></td><td>13,388</td><td></td></tr></table>

Question: What do all Net Generation (MWh) sum up in 2014 , excluding Gulf Coast and East? (in thousand)
Answer: 16640