Pension Expense
## Table 0 ##
Pension expense decreased from the prior year due to lower pension settlements, lower loss amortization, primarily from favorable asset experience and the impact of higher discount rates, partially offset by lower expected returns on assets.
Special items (settlements, termination benefits, and curtailments) decreased from the prior year primarily due to lower pension settlement losses.
In fiscal year 2019, special items of $7.2 included pension settlement losses of $6.4, of which $5.0 was recorded during the second quarter and related to the U. S.  Supplementary Pension Plan, and $.8 of termination benefits.
These amounts are reflected within "Other nonoperating income (expense), net" on the consolidated income statements.
In fiscal year 2018, special items of $48.9 included a pension settlement loss of $43.7 primarily in connection with the transfer of certain pension assets and payment obligations for our U. S.  salaried and hourly plans to an insurer during the fourth quarter, $4.8 of pension settlement losses related to lump sum payouts from the U. S.  Supplementary Pension Plan, and $.4 of termination benefits.
U. K.  Lloyds Equalization Ruling On 26 October 2018, the United Kingdom High Court issued a ruling related to the equalization of pension plan participants’ benefits for the gender effects of Guaranteed Minimum Pensions.
As a result of this ruling, we estimated the impact of retroactively increasing benefits in our U. K.  plan in accordance with the High Court ruling.
We treated the additional benefits as a prior service cost, which resulted in an increase to our projected benefit obligation and accumulated other comprehensive loss of $4.7 during the first quarter of fiscal year 2019.
We are amortizing this cost over the average remaining life expectancy of the U. K.  participants.2020 Outlook In fiscal year 2020, we expect pension expense to be approximately $5 to $20, which includes expected pension settlement losses of $5 to $10, depending on the timing of retirements.
The expected range reflects lower expected interest cost and higher total assets, partially offset by higher expected loss amortization primarily due to the impact of lower discount rates.
In fiscal year 2020, we expect pension expense to include approximately $105 for amortization of actuarial losses.
In fiscal year 2019, pension expense included amortization of actuarial losses of $76.2.
Net actuarial losses of $424.4 were recognized in accumulated other comprehensive income in fiscal year 2019.
Actuarial (gains) losses are amortized into pension expense over prospective periods to the extent they are not offset by future gains or losses.
Future changes in the discount rate and actual returns on plan assets different from expected returns would impact the actuarial (gains) losses and resulting amortization in years beyond fiscal year 2020.
Pension Funding Pension funding includes both contributions to funded plans and benefit payments for unfunded plans, which are primarily non-qualified plans.
With respect to funded plans, our funding policy is that contributions, combined with appreciation and earnings, will be sufficient to pay benefits without creating unnecessary surpluses.
In addition, we make contributions to satisfy all legal funding requirements while managing our capacity to benefit from tax deductions attributable to plan contributions.
With the assistance of third-party actuaries, we analyze the liabilities and demographics of each plan, which help guide the level of contributions.
During 2019 and 2018, our cash contributions to funded plans and benefit payments for unfunded plans were $40.2 and $68.3, respectively.
For fiscal year 2020, cash contributions to defined benefit plans are estimated to be $30 to $40.
The estimate is based on expected contributions to certain international plans and anticipated benefit payments for unfunded plans, which are dependent upon the timing of retirements.
Actual future contributions will depend on future funding legislation, discount rates, investment performance, plan design, and various other factors.
Refer to the Contractual Obligations discussion on page 37 for a projection of future contributions.
Noble Energy, Inc.  Notes to Consolidated Financial Statements 89 Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
## Table 1 ##
The following table provides an aging of capitalized exploratory well costs (suspended well costs) based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
## Table 2 ##
The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of December 31, 2010:
## Table 3 ##
Blocks O and I (West Africa) The West Africa project includes Blocks O and I offshore Equatorial Guinea and the YoYo mining concession and Tilapia PSC offshore Cameroon.
In December 2010, we and our partners sanctioned the development plan for Alen, which was subsequently approved by the government of Equatorial Guinea in January 2011.
Approximately $61 million of capitalized costs were reclassified to proved oil and gas properties.
In 2009, we sanctioned the Aseng development project and reclassified $76 million of capitalized costs to proved oil and gas properties.
We are evaluating future oil projects and planning to drill an appraisal well at Diega/Carmen, offshore Equatorial Guinea.
In Cameroon, we recently completed a 3-D seismic acquisition, and results are being processed for future drilling potential.
Dalit (Israel) Dalit is a 2009 natural gas discovery located offshore Israel.
We are currently working with our partners on a cost-effective development plan.
In 2010, we sanctioned the Tamar development project and reclassified $77 million of capitalized costs to proved oil and gas properties.
Gunflint (Deepwater Gulf of Mexico) Gunflint (Mississippi Canyon Block 948) is a 2008 crude oil discovery.
Our plans to drill one or two appraisal wells in 2010 were delayed by the Deepwater Moratorium.
Once a drilling permit is approved, we plan to drill one or two appraisal wells.
We are also reviewing host platform options including: subsea tieback to an existing third-party host, procurement and modification of an existing platform, and new construction.
If we are able to connect to an existing third-party host, the project could have an accelerated completion schedule, thereby potentially absorbing time lost due to the drilling delay caused by the Deepwater Moratorium.
daily production base, starting from the closing date, and will provide significant growth potential.
Included in the purchase were 323,000 total net acres, nearly 183,000 of which are located in the Central DJ Basin.
See United States discussion below.
Onshore US Sale In August 2010, we closed the sale of non-core assets in the Mid-Continent and Illinois Basin areas for cash proceeds of $552 million and recorded a gain of $110 million.
The sale included approximately 32 MMBoe of proved reserves, at closing date, and approximately 5.7 MBoe/d of production.
Mid-Continent Acquisition In 2008, we acquired producing properties in western Oklahoma for $292 million.
Properties acquired cover approximately 15,500 net acres and included approximately 16 MMBoe of proved reserves.
Sale of Argentina Assets In 2008, we closed on the sale of our producing property interest in Argentina for a sales price of $117.5 million.
Our crude oil reserves for Argentina totaled 7 MMBbls at December 31, 2007.
Deepwater Horizon Incident In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon, engaged in drilling operations for another operator, sank after a blowout and fire (Deepwater Horizon Incident or Incident).
The resulting leak caused a significant oil spill.
Subsequently, the Secretary of the Interior ceased issuing offshore drilling permits pursuant to a series of moratoria, and all deepwater drilling activities in progress were suspended (Deepwater Moratorium).
Although the moratoria have been lifted for drilling in water depths greater than 500 feet, the US Department of the Interior has not issued any permits related to the drilling of new exploratory wells as of January 31, 2010.
Additionally, the US administration and the Department of the Interior have maintained the ban on new drilling on the Atlantic Coast and in the Eastern Gulf of Mexico.
The Deepwater Horizon Incident is likely to have a significant and lasting effect on the US offshore energy industry, and has resulted in a number of fundamental changes, including heightened regulatory scrutiny, more stringent operating and safety standards and changes in equipment requirements.
Other countries, including some in which we currently conduct business, are considering legislative or regulatory changes which could also have an impact on offshore drilling activities.
These changes may result in increases in our operating and development costs and extend project development timelines.
We are monitoring legislative and regulatory developments and are currently unsure of the full impact of the Incident.
See Deepwater Gulf of Mexico, below, and Item 1A.
Risk Factors Our operations in the deepwater Gulf of Mexico, as well as onshore US and international locations, could be adversely affected by future changes in laws and regulations which may occur as a result of the Deepwater Horizon Incident.
Termination of Ecuador PSC In November 2010, we announced that we had received notice from the government of Ecuador regarding the termination of the Block 3 production sharing contract (PSC) (100% working interest) with our subsidiary, EDC Ecuador Ltd.  as we had not negotiated a service contract on Block 3 in accordance with the terms of a newly enacted hydrocarbon law.
The Ecuadorian hydrocarbon law aims to change current production sharing arrangements into service contracts and provided for renegotiation of certain contracts by November 23, 2010.
It also allows the Ecuadorian government to nationalize oil and gas fields if a private operator does not comply with local laws.
We are continuing to work with the government of Ecuador to resolve this matter.
However, we are uncertain as to the potential outcome of this matter, resolution of which could ultimately lead to a reduction in the value of our investment in Ecuador which, as of December 31, 2010, had a net book value of approximately $66 million.
United States We have been engaged in crude oil and natural gas exploration, exploitation and development activities throughout onshore US since 1932 and in the Gulf of Mexico since 1968.
US operations accounted for 57% of our 2010 total consolidated sales volumes and 45% of total proved reserves at December 31, 2010.
Approximately 55% of the proved reserves are natural gas and 45% are crude oil, condensate and NGLs.
Sales of production and estimates of proved reserves for our US operating areas were as follows:
## Table 4 ##
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 – Regulation and the following risk factors listed in Item 1A.
Risk Factors – ?
We are subject to increasing governmental regulations and environmental risks that may cause us to incur substantial costs; ?
Increased regulation of business practices could result in increased operating costs; and ?
The adoption of GHG emission or other environmental legislation could result in increased 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 2010 total consolidated production was natural gas.
GHG emissions regulation could reduce the demand for the crude oil and natural gas 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.
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 become 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 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.
See Item 1A.
Risk Factors – We have insufficient insurance to cover all of the risks we face, which could result in significant financial exposure.
RESULTS OF OPERATIONS Selected financial information is as follows:
## Table 5 ##
Factors contributing to the increase in income (loss) before income taxes in 2010 as compared with 2009 included the following: ?
$709 million increase in total revenues due primarily to higher commodity prices; ?
$460 million decrease in asset impairment charges; ?
$91 million increase in net gain on asset sales; and ?
$157 million mark-to-market gain on commodity derivative instruments as opposed to a $110 million mark-tomarket loss in 2009; offset by: ?
$45 million increase in total production expense; ?
$101 million increase in exploration expense; and ?
$67 million increase in DD&A expense.
than if we had no derivative instruments.
None of our counterparty agreements currently contain margin requirements.
However, see Item 1A.
Risk Factors – Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.
See Critical Accounting Policies and Estimates – Derivative Instruments and Hedging Activities, Item 7A.
Quantitative and Qualitative Disclosures About Market Risk, and Item 8.
Financial Statements and Supplementary Data – Note 10.
Derivative Instruments and Hedging Activities.
Accounts Receivable We have accounts receivable from sales of our crude oil, natural gas and NGLs, as well as electricity.
We also have accounts receivable from joint venture partners for their share of expenses on joint venture projects for which we are the operator.
Some of these parties are not as creditworthy as we are and may experience liquidity problems.
We have obtained credit enhancements from some parties in the way of parental guarantees or letters of credit, including our largest crude oil purchaser; however, not all of our trade credit is protected through guarantees or credit support.
Nonperformance by a trade creditor or joint venture partner could result in losses.
Other than reductions in the carrying value of a receivable from SemCrude, L. P. , a crude oil purchaser that declared bankruptcy in 2008, and certain entities purchasing electricity in Ecuador, we have experienced no significant collection issues with purchasers or joint venture partners.
See Item 1A.
Risk Factors – We are exposed to counterparty credit risk as a result of our receivables, hedging transactions, and cash investments and Item 8.
Financial Statements and Supplementary Data – Note 5.
Allowance for Doubtful Accounts.
Cash Flows Summary cash flow information is as follows:

<table><tr><td></td><td>2019</td><td>2018</td></tr><tr><td>Pension expense, including special items noted below</td><td>$27.6</td><td>$91.8</td></tr><tr><td>Settlements, termination benefits, and curtailments ("special items")</td><td>7.2</td><td>48.9</td></tr><tr><td>Weighted average discount rate – Service cost</td><td>3.4%</td><td>3.2%</td></tr><tr><td>Weighted average discount rate – Interest cost</td><td>3.4%</td><td>2.9%</td></tr><tr><td>Weighted average expected rate of return on plan assets</td><td>6.4%</td><td>6.9%</td></tr><tr><td>Weighted average expected rate of compensation increase</td><td>3.5%</td><td>3.5%</td></tr></table>
<table><tr><td></td><td colspan="3">Year Ended December 31,</td></tr><tr><td></td><td>2010</td><td>2009</td><td>2008</td></tr><tr><td>(millions)</td><td></td><td></td><td></td></tr><tr><td>Capitalized Exploratory Well Costs, Beginning of Period</td><td>$432</td><td>$501</td><td>$249</td></tr><tr><td>Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves</td><td>143</td><td>136</td><td>253</td></tr><tr><td>Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves</td><td>-146</td><td>-198</td><td>-</td></tr><tr><td>Capitalized Exploratory Well Costs Charged to Expense</td><td>-3</td><td>-7</td><td>-1</td></tr><tr><td>Capitalized Exploratory Well Costs, End of Period</td><td>$426</td><td>$432</td><td>$501</td></tr></table>
<table><tr><td></td><td colspan="3">December 31,</td></tr><tr><td></td><td>2010</td><td>2009</td><td>2008</td></tr><tr><td>(millions)</td><td></td><td></td><td></td></tr><tr><td>Exploratory Well Costs Capitalized for a Period of One Year or Less</td><td>$148</td><td>$158</td><td>$256</td></tr><tr><td>Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling</td><td>278</td><td>274</td><td>245</td></tr><tr><td>Balance at End of Period</td><td>$426</td><td>$432</td><td>$501</td></tr><tr><td>Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year After Completion of Drilling</td><td>8</td><td>5</td><td>6</td></tr></table>
<table><tr><td></td><td></td><td colspan="3">Suspended Since</td></tr><tr><td></td><td>Total</td><td>2009</td><td>2008</td><td>2007 & Prior</td></tr><tr><td>(millions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Project</td><td></td><td></td><td></td><td></td></tr><tr><td>Blocks O and I (West Africa)</td><td>$133</td><td>$14</td><td>$9</td><td>$110</td></tr><tr><td>Dalit (Israel)</td><td>20</td><td>20</td><td>-</td><td>-</td></tr><tr><td>Gunflint (Deepwater Gulf of Mexico)</td><td>52</td><td>3</td><td>49</td><td>-</td></tr><tr><td>Redrock (Deepwater Gulf of Mexico)</td><td>17</td><td>-</td><td>-</td><td>17</td></tr><tr><td>Deep Blue (Deepwater Gulf of Mexico)</td><td>19</td><td>19</td><td>-</td><td>-</td></tr><tr><td>Flyndre (North Sea)</td><td>13</td><td>-</td><td>-</td><td>13</td></tr><tr><td>Selkirk (North Sea)</td><td>20</td><td>-</td><td>-</td><td>20</td></tr><tr><td>Other</td><td>4</td><td>1</td><td>3</td><td>-</td></tr><tr><td>Total Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling</td><td>$278</td><td>$57</td><td>$61</td><td>$160</td></tr></table>
<table><tr><td></td><td colspan="4">Year Ended December 31, 2010 Sales Volumes</td><td colspan="3">December 31, 2010 Proved Reserves</td></tr><tr><td></td><td>Crude Oil & Condensate</td><td>Natural Gas</td><td>NGLs</td><td>Total</td><td>Crude Oil, Condensate & NGLs</td><td>Natural Gas</td><td>Total</td></tr><tr><td></td><td>(MBbl/d)</td><td>(MMcf/d)</td><td>(MBbl/d)</td><td>(MBoe/d)</td><td>(MMBbls)</td><td>(Bcf)</td><td>(MMBoe)</td></tr><tr><td>Wattenberg</td><td>19</td><td>151</td><td>10</td><td>54</td><td>177</td><td>851</td><td>319</td></tr><tr><td>Rocky Mountain/Mid-Continent</td><td>5</td><td>171</td><td>1</td><td>36</td><td>16</td><td>646</td><td>123</td></tr><tr><td>Deepwater Gulf of Mexico</td><td>11</td><td>40</td><td>2</td><td>19</td><td>22</td><td>34</td><td>28</td></tr><tr><td>Gulf Coast and Other Onshore</td><td>4</td><td>38</td><td>1</td><td>10</td><td>10</td><td>95</td><td>26</td></tr><tr><td>Total</td><td>39</td><td>400</td><td>14</td><td>119</td><td>225</td><td>1,626</td><td>496</td></tr></table>
<table><tr><td></td><td colspan="3">Year Ended December 31,</td></tr><tr><td></td><td>2010</td><td>2009</td><td>2008</td></tr><tr><td>(millions, except per share)</td><td></td><td></td><td></td></tr><tr><td>Total Revenues</td><td>$3,022</td><td>$2,313</td><td>$3,901</td></tr><tr><td>Total Operating Expenses</td><td>2,070</td><td>2,371</td><td>2,266</td></tr><tr><td>Operating Income (Loss)</td><td>952</td><td>-58</td><td>1,635</td></tr><tr><td>Total Other (Income) Expense</td><td>-79</td><td>206</td><td>-426</td></tr><tr><td>Income (Loss) Before Income Taxes</td><td>1,031</td><td>-264</td><td>2,061</td></tr><tr><td>Net Income (Loss)</td><td>725</td><td>-131</td><td>1,350</td></tr><tr><td>Earnings (Loss) Per Share</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$4.15</td><td>$-0.75</td><td>$7.83</td></tr><tr><td>Diluted</td><td>4.10</td><td>-0.75</td><td>7.58</td></tr></table>

Question: How many kinds of December 31 are greater than 200 in 2010?
Answer: 2