ÿþIf 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:  @T@  Crude Oil and Condensate Sales 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 Central DJ Basin, including horizontal   drilling in the Niobrara formation;   ·additional production from the Central DJ Basin asset acquisition in March 2010;   ·crude oil production from a Swordfish sidetrack 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 mature oil 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 sales decreased by a net $840 million, or 40%, in 2009 as compared with 2008 due to the   following:   ·a 32% decline in consolidated average realized prices due to the decreased demand for oil resulting from   the economic slowdown;   ·natural field decline in the deepwater Gulf of Mexico and Gulf Coast area;   ·the shut-in of Ticonderoga in the deepwater Gulf of Mexico until August 2009 after being offline due to   Hurricane Ike in 2008;   ·a decrease in Equatorial Guinea sales volumes due to timing of liftings; and   ·a decrease in North Sea sales volumes due to natural field decline and downtime beginning in mid-August at   the Dumbarton field due to FPSO repairs;   partially offset by   ·increased production due to ongoing development activity in the Central DJ Basin.
   Crude oil revenues include amounts reclassified from AOCL related to commodity derivative instruments which were   accounted for as cash flow hedges through December 31, 2007.
 Amounts included decreases of $19 million in 2010,   $58 million in 2009, and $365 million in 2008.
 At 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.
   Natural Gas Sales Revenues from natural gas sales increased by a net $133 million, or 19%, in 2010 as compared   with 2009 due to the following:   ·an increase in total consolidated and US average realized prices due to increased demand resulting from   the economic recovery;   ·an increase in Israel average realized prices under the terms of a natural gas sales contract entered into in   the third quarter of 2009;   ·increased production due to ongoing development activity in the Central DJ Basin, including the horizontal   drilling in the Niobrara formation;   ·additional production from the Central DJ Basin asset acquisition in March 2010; and
## Table 0 ##
the year are summarized below:
## Table 1 ##
Revisions of previous estimates include the transfer of PUDs to unproved reserve categories as a result of changes in development plans and/or the impact of changes in commodity prices, and the addition of new PUDs arising from current development plans.
Negative revisions of 177 MMBoe in the US for 2015 included: ?
the transfer to unproved reserves of 183 MMBoe due to negative price revisions attributed to low commodity price outlook and negative revisions of 48 MMBoe due to reduced future development activity, primarily in the DJ Basin; offset by: ?54 MMBoe positive revisions primarily in the Marcellus Shale, Eagle Ford Shale and Permian Basin due to current drilling and development plans.
Extensions, discoveries and other additions include addition of proved reserves through additional drilling or the discovery of new reservoirs in proven fields.
During 2015, we recorded additions of 68 MMBoe and 9 MMBoe in the DJ Basin and Marcellus Shale, respectively, as a result of successful expansion of our extended reach lateral well programs.
Purchases of minerals included 119 MMBoe and 24 MMBoe in the Eagle Ford Shale and Permian Basin, respectively, as a result of the Rosetta Merger.
Conversion to proved developed reserves primarily included the transfer of 39 MMBoe, 22 MMBoe, 17 MMBoe and 11 MMBoe from the Marcellus Shale, DJ Basin, Eagle Ford Shale and deepwater Gulf of Mexico, respectively.
In 2015, we converted 89 MMBoe of US PUDs, or 23% of our 2014 US PUD balance, to developed status.
Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling and completion activity, we expect our US PUDs as of December 31, 2015 to be converted to proved developed reserves well within a five-year period.
US PUDs Locations As of December 31, 2015, our US PUDs included: ?147 MMBoe in the DJ Basin; ?50 MMBoe in the Marcellus Shale; ?102 MMBoe in the Eagle Ford Shale; ?31 MMBoe in the Permian Basin; and ?14 MMBoe in the deepwater Gulf of Mexico primarily associated with the Gunflint project.
Our PUDs are expected to be recovered from new wells on undrilled acreage or from existing wells where additional capital expenditures are required for completion, such as drilled but uncompleted (DUC) wells.
As of December 31, 2015, we had approximately 98 MMBoe of proved undeveloped reserves associated with DUC well locations related to our onshore US operations, approximately one-half of which are in the Marcellus Shale, nearly one-third are in the Eagle Ford Shale and the remainder are in the DJ Basin and Permian Basin.
International PUDs Locations As of December 31, 2015, our international PUDs included: ?70 MMBoe in the Alba field, offshore Equatorial Guinea, all of which have been recorded as PUDs for over five years and are attributable to a sanctioned compression project which is currently under construction and expected to come online mid-2016.
These volumes, which will be recovered through existing wells, will be reclassified to proved developed at start-up, currently expected in second quarter 2016; and ?71 MMBoe in Israel primarily in the Tamar and Tamar Southwest fields, including PUDs of 32 MMBoe related to the Tamar Southwest field, which is awaiting government approval of the development plan.
Table of Contents Noble Energy, Inc.  Index to Financial Statements Notes to Consolidated Financial Statements 112 Note 4.
Noble Midstream Partners LP Noble Midstream Partners LP In December 2014, we formed Noble Midstream Partners LP, a growth-oriented Delaware master limited partnership, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets.
Noble Midstream Partners' current areas of focus are in the DJ Basin in Colorado and in the Delaware Basin within the Permian Basin in Texas.
Initial Public Offering of Noble Midstream Partners LP On September 15, 2016, Noble Midstream Partners common units began trading on the New York Stock Exchange under the symbol "NBLX. "
On September 20, 2016, Noble Midstream Partners completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream Partners, which included 1,875,000 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price to the public of $22.50 per common unit ($21.21 per common unit, net of underwriting discounts).
In exchange for the contributed assets, Noble Energy received: ?1,527,584 common units, representing a 4.8% limited partner interest in Noble Midstream Partners; ?15,902,584 subordinated units, representing an approximate 50.0% limited partner interest in Noble Midstream Partners; ?
incentive distribution rights in Noble Midstream Partners; and ?
the right to receive a cash distribution from Noble Midstream Partners.
In addition and concurrent with the closing of the offering, the General Partner retained a non-economic general partnership interest in Noble Midstream Partners, which is not entitled to receive cash distributions.
Noble Midstream Partners generated net proceeds of $299 million from the issuance of common units to the public, after deducting the underwriting discount, structuring fees and estimated offering expenses of $24 million.
Note 5.
Asset Impairments Pre-tax (non-cash) asset impairment charges were as follows:
## Table 2 ##
2016 Asset Impairments While the Leviathan development project was not formally sanctioned at December 31, 2016, in fourth quarter 2016, we selected the initial development concept for the first phase of development of the Leviathan natural gas project and wrote off $88 million associated with certain development concepts that were not selected.2015 Asset Impairments During 2015, certain properties in the deepwater Gulf of Mexico, offshore Israel and offshore Equatorial Guinea were written down to their estimated fair values using a discounted cash flow model.
The cash flow model included management’s estimates of future crude oil and natural gas production, commodity prices based on forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and discount rates.
Impairment charges of $481 million resulted from reductions in the forward crude oil prices as of December 31, 2015.
We also recorded impairment charges of approximately $47 million primarily related to revisions in expected field abandonment and other costs for properties in the deepwater Gulf of Mexico and offshore Israel and $5 million related to the pending sale of our interest in the Alon A and Alon C licenses, offshore Israel, which included the Karish and Tanin fields.2014 Asset Impairments As a result of declining crude oil prices at the end of 2014, we recorded impairment charges of $250 million related to certain onshore US and deepwater Gulf of Mexico properties.
We also recorded impairment charges of $74 million for the South Raton development, deepwater Gulf of Mexico, due to mechanical issues; $51 million related to asset retirement obligation increases for certain properties in the deepwater Gulf of Mexico and offshore Israel; $31 million related to the reclassification of certain non-strategic properties as assets held for sale; and $94 million related to North Sea MacCulloch field abandonment.
REPUBLIC SERVICES, INC.  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) We determine the discount rate used in the measurement of our obligations based on a model that matches the timing and amount of expected benefit payments to maturities of high quality bonds priced as of the pension plan measurement date.
When that timing does not correspond to a published high-quality bond rate, our model uses an expected yield curve to determine an appropriate current discount rate.
The yields on the bonds are used to derive a discount rate for the liability.
The term of our obligation, based on the expected retirement dates of our workforce, is approximately ten years.
In developing our expected rate of return assumption, we have evaluated the actual historical performance and long-term return projections of the Plan assets, which give consideration to the asset mix and the anticipated timing of the pension plan outflows.
We employ a total return investment approach whereby a mix of equity and fixed income investments are used to maximize the long-term return of plan assets for what we consider a prudent level of risk.
The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run.
Risk tolerance is established through careful consideration of plan liabilities, plan funded status and our financial condition.
The investment portfolio contains a diversified blend of equity and fixed income investments.
Furthermore, equity investments are diversified across U. S.  and non-U.
S.  stocks as well as growth, value, and small and large capitalizations.
Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investments.
Investment risk is measured and monitored on an ongoing basis through annual liability measurements, periodic asset and liability studies, and quarterly investment portfolio reviews.
The following table summarizes our target asset allocation for 2014 and actual asset allocation as of December 31, 2014 and 2013 for our defined benefit pension plan:

Tables referenced above, in order (Table 0 first):
<table><tr><td></td><td colspan="6">Commodity Price Increase (Decrease)</td></tr><tr><td></td><td colspan="2">2010</td><td colspan="2">2009</td><td colspan="2">2008</td></tr><tr><td></td><td>Crude Oil & Condensate</td><td>Natural Gas</td><td>Crude Oil & Condensate</td><td>Natural Gas</td><td>Crude Oil & Condensate</td><td>Natural Gas</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>Year Ended December 31,</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$-0.65</td><td>$0.76</td><td>$12.26</td><td>$1.73</td><td>$-3.85</td><td>$-0.07</td></tr><tr><td>Equatorial Guinea</td><td>-3.41</td><td>-</td><td>15.36</td><td>-</td><td>-2.97</td><td>-</td></tr><tr><td>Total Consolidated Operations</td><td>-1.00</td><td>0.40</td><td>10.86</td><td>0.91</td><td>-2.85</td><td>-0.04</td></tr><tr><td>Total</td><td>-0.97</td><td>0.40</td><td>10.55</td><td>0.91</td><td>-2.77</td><td>-0.04</td></tr></table>
<table><tr><td></td><td>UnitedStates</td><td>EquatorialGuinea</td><td>Israel</td><td>Total</td></tr><tr><td>(MMBoe)</td><td></td><td></td><td></td><td></td></tr><tr><td>Proved Undeveloped Reserves Beginning of Year</td><td>390</td><td>59</td><td>74</td><td>523</td></tr><tr><td>Revisions of Previous Estimates</td><td>-177</td><td>2</td><td>-3</td><td>-178</td></tr><tr><td>Extensions, Discoveries and Other Additions</td><td>77</td><td>—</td><td>—</td><td>77</td></tr><tr><td>Purchase of Minerals in Place</td><td>143</td><td>—</td><td>—</td><td>143</td></tr><tr><td>Sale of Minerals in Place</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Conversion (to) from Proved Developed</td><td>-89</td><td>9</td><td>—</td><td>-80</td></tr><tr><td>Proved Undeveloped Reserves End of Year</td><td>344</td><td>70</td><td>71</td><td>485</td></tr></table>
<table><tr><td></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>(millions)</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Onshore US</td><td>$—</td><td>$—</td><td>$42</td></tr><tr><td>Deepwater Gulf of Mexico</td><td>—</td><td>158</td><td>350</td></tr><tr><td>Israel</td><td>88</td><td>36</td><td>14</td></tr><tr><td>Equatorial Guinea</td><td>—</td><td>339</td><td>—</td></tr><tr><td>North Sea</td><td>—</td><td>—</td><td>94</td></tr><tr><td>Other International and Corporate</td><td>4</td><td>—</td><td>—</td></tr><tr><td>Total</td><td>$92</td><td>$533</td><td>$500</td></tr></table>

Question: Which year is the Commodity Price Increase of Natural Gas totally larger?
Answer: 2009