CF INDUSTRIES HOLDINGS, INC.  116 15.
Derivative Financial Instruments We use derivative financial instruments to reduce our exposure to changes in commodity prices and foreign currency exchange rates.
Commodity Price Risk Management Natural gas is the largest and most volatile component of the manufacturing cost for nitrogen-based products.
We manage the risk of changes in natural gas prices primarily through the use of derivative financial instruments.
The derivatives that we use for this purpose are primarily natural gas fixed price swaps and natural gas options traded in the OTC markets.
These natural gas derivatives settle using primarily a NYMEX futures price index, which represents the basis for fair value at any given time.
We enter into natural gas derivative contracts with respect to natural gas to be consumed by us in the future, and settlements of those derivative contracts are scheduled to coincide with our anticipated purchases of natural gas used to manufacture nitrogen products during those future periods.
We use natural gas derivatives as an economic hedge of natural gas price risk, but without the application of hedge accounting.
As a result, changes in fair value of these contracts are recognized in earnings.
As of December 31, 2016, we have natural gas derivative contracts covering periods through the end of 2018.
As of December 31, 2016 and 2015, we had open natural gas derivative contracts for 183.0 million MMBtus and 431.5 million MMBtus, respectively.
For the year ended December 31, 2016, we used derivatives to cover approximately 84% of our natural gas consumption.
Foreign Currency Exchange Rates A portion of the costs for our capacity expansion projects at our Donaldsonville, Louisiana complex and Port Neal, Iowa complex were euro-denominated.
In order to manage our exposure to changes in the euro to U. S.  dollar currency exchange rates, we hedged our projected euro-denominated payments through the end of 2016 using foreign currency forward contracts.
CF INDUSTRIES HOLDINGS, INC.  116 15.
Derivative Financial Instruments We use derivative financial instruments to reduce our exposure to changes in commodity prices and foreign currency exchange rates.
Commodity Price Risk Management Natural gas is the largest and most volatile component of the manufacturing cost for nitrogen-based products.
We manage the risk of changes in natural gas prices primarily through the use of derivative financial instruments.
The derivatives that we use for this purpose are primarily natural gas fixed price swaps and natural gas options traded in the OTC markets.
These natural gas derivatives settle using primarily a NYMEX futures price index, which represents the basis for fair value at any given time.
We enter into natural gas derivative contracts with respect to natural gas to be consumed by us in the future, and settlements of those derivative contracts are scheduled to coincide with our anticipated purchases of natural gas used to manufacture nitrogen products during those future periods.
We use natural gas derivatives as an economic hedge of natural gas price risk, but without the application of hedge accounting.
As a result, changes in fair value of these contracts are recognized in earnings.
As of December 31, 2016, we have natural gas derivative contracts covering periods through the end of 2018.
As of December 31, 2016 and 2015, we had open natural gas derivative contracts for 183.0 million MMBtus and 431.5 million MMBtus, respectively.
For the year ended December 31, 2016, we used derivatives to cover approximately 84% of our natural gas consumption.
Foreign Currency Exchange Rates A portion of the costs for our capacity expansion projects at our Donaldsonville, Louisiana complex and Port Neal, Iowa complex were euro-denominated.
In order to manage our exposure to changes in the euro to U. S.  dollar currency exchange rates, we hedged our projected euro-denominated payments through the end of 2016 using foreign currency forward contracts.
As of December 31, 2015, the notional amount of our open foreign currency derivatives was €89 million.
None of these open foreign currency derivatives were designated as hedging instruments for accounting purposes.
All of these foreign currency derivatives settled in 2016.
As of December 31, 2016, accumulated other comprehensive loss (AOCL) includes $7 million of pre-tax gains related to the foreign currency derivatives that were originally designated as cash flow hedges.
The hedges were de-designated as of December 31, 2013.
The remaining balance in AOCL is being reclassified into income over the depreciable lives of the property, plant and equipment associated with the capacity expansion projects.
The amounts reclassified into income from AOCL during the years ended December 31, 2016, 2015 and 2014 were zero, zero and $3 million, respectively, and are included in other operating¡ªnet in our consolidated statements of operations.
We expect that the amounts to be reclassified within the next twelve months will be insignificant.
During the years ended December 31, 2016, 2015, and 2014, none of our derivatives were designated as hedges and no gain or loss was recognized in income or AOCL related to derivatives designated as cash flow hedges except for the amounts recognized in income, which were reclassified from AOCL, as discussed above.
The effect of derivatives in our consolidated statements of operations is shown in the table below:
## Table 0 ##
UAN Segment Our UAN segment produces urea ammonium nitrate solution (UAN).
UAN, a liquid fertilizer product with a nitrogen content that typically ranges from 28% to 32%, is produced by combining urea and ammonium nitrate.
UAN is produced at our nitrogen complexes in Courtright, Ontario; Donaldsonville, Louisiana; Port Neal, Iowa; Verdigris, Oklahoma; Woodward, Oklahoma; and Yazoo City, Mississippi.
The following table presents summary operating data for our UAN segment:
## Table 1 ##
(1) UAN represents between 28% and 32% of nitrogen content, depending on the concentration specified by the customer.
Nutrient tons represent the tons of nitrogen within the product tons.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 Net Sales.
Net sales in the UAN segment decreased $284 million, or 19%, in 2016 due primarily to a 29% decrease in average selling prices partially offset by a 14% increase in sales volume.
Average selling prices decreased to $179 per ton in 2016 compared to $252 in 2015.
UAN selling prices were lower due to excess global nitrogen supply weighing on global nitrogen fertilizer selling prices.
Increases in UAN exports at lower selling prices also negatively impacted our average selling price.
Sales volume was higher due to increased production as a result of expanded UAN capacity at our Donaldsonville, Louisiana complex that came on line in the first quarter of 2016.
Cost of Sales.
Cost of sales per ton in our UAN segment averaged $138 in 2016, a 15% decrease from the average of $162 per ton in 2015.
The decrease was due primarily to the impact of unrealized net mark-to-market gains on natural gas derivatives in 2016 compared to losses in 2015 and the impact of lower realized natural gas cost in 2016.
This was partly offset by increased depreciation expense related to the expanded UAN capacity at our Donaldsonville, Louisiana complex that came on line in the first quarter of 2016.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 Net Sales.
Net sales in the UAN segment decreased by $190 million, or 11%, due to a 8% decrease in average selling prices and a 4% decrease in sales volume.
Average selling prices decreased to $252 per ton in 2015 compared to $274 per ton in 2014.
The decline in UAN average selling prices was due to excess global nitrogen supply weighing on global nitrogen fertilizer selling prices.
Sales volume was lower as customers delayed purchases in the declining pricing environment.
Cost of Sales.
Cost of sales per ton in our UAN segment averaged $162 in 2015, a 1% decrease over the $164 per ton in 2014.
The decrease was due primarily to lower realized natural gas costs partly offset by the impact of higher unrealized net mark-to-market losses on natural gas derivatives in 2015 compared to 2014.
Outlook Budget Our Board of Directors approved a Budget of $3.5 billion for 2015, including capital expenditures of $3.4 billion.
With the continued uncertainty in commodity pricing, we have taken decisive action to protect our optionality and position us to be a stronger E&P company in the long term.
Our exploration spending has been reduced by more than 50 percent while we continue to focus on our three U. S.  resource plays.
We are also prepared to exercise further flexibility in our spend levels as pricing and the macro environment warrant.
Our Budget is broken down by reportable segment in the table below.
## Table 2 ##
(a) Represents the net budget after factoring in reimbursements from the Canadian Federal and Provincial government related to the QUEST CCS project.
North America E&P – Approximately $2.4 billion of our Budget is allocated to our three core U. S.  resource plays.
More than $1.4 billion is earmarked for the Eagle Ford, where rig count is expected to drop from 18 in late 2014 to 10 by the end of the second quarter of 2015.
Included in Eagle Ford spending is approximately $1 billion for drilling and completions.
We plan to spend $760 million in the Bakken in North Dakota.
Drilling activity will be reduced to two rigs by the end of the first quarter of 2015, down from seven rigs at the end of 2014.
Bakken spending includes approximately $550 million for drilling, completions and recompletions.
Spending of $226 million is targeted for the Oklahoma Resource Basins, which will also be down to two rigs by the end of the first quarter of 2015.
This includes spending of approximately $200 million for drilling and completions.
International E&P – We plan to spend approximately $429 million on our international assets, primarily in E. G. , the U. K.  and the Kurdistan Region of Iraq.
Approximately $232 million will be spent on a targeted exploration program impacting both the North America E&P and the International E&P segments.
The program includes one operated Gulf of Mexico well, participation in a non-operated appraisal well at Shenandoah in the Gulf of Mexico and seismic surveys in Gabon and Ethiopia.
Oil Sands Mining – We expect to spend $95 million for sustaining capital projects in the OSM segment.
We hold a 20 percent outside-operated interest in the Athabasca Oil Sands Project.
The remainder of our Budget consists of Corporate and Other and is expected to total approximately $79 million, of which $40 million represents capitalized interest on assets under construction.
For information about expected exploration and development activities more specific to individual assets, see Item 1.  Business.
Production Volumes We forecast 2015 production available for sale from the combined North America E&P and International E&P segments, excluding Libya, to be 370 to 390 net mboed and the OSM segment to be 35 to 45 net mbbld of synthetic crude oil.
We expect our U. S.  resource plays to achieve production growth of approximately 20 percent in 2015 over 2014.
In addition, we expect total production growth, excluding Libya, of 5 to 7 percent year-over-year.
Acquisitions and Dispositions Excluded from our Budget are the impacts of acquisitions and dispositions not previously announced.
We continually evaluate ways to optimize our portfolio through acquisitions and divestitures.
In connection with our ongoing portfolio management, future decisions to dispose of assets could result in non-cash impairments in the period such decisions are made.
Personnel In February 2015, we announced a reduction in workforce impacting approximately 350-400 employees.
These reductions focus largely on U. S.  payroll employees, weighted toward above-the-field and support services personnel, though we will continue to analyze our staffing needs at all levels and in all locations.
Affected employees will be eligible for severance benefits

Tables referenced above, in order (Table 0 first):
<table><tr><td></td><td colspan="4">Gain (loss) in income</td></tr><tr><td></td><td></td><td colspan="3">Year ended December 31,</td></tr><tr><td></td><td>Location</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td></td><td></td><td colspan="3">(in millions)</td></tr><tr><td>Natural gas derivatives</td><td>Cost of sales</td><td>$260</td><td>$-176</td><td>$-79</td></tr><tr><td>Foreign exchange contracts</td><td>Other operating—net</td><td>—</td><td>22</td><td>-44</td></tr><tr><td>Unrealized gains (losses) recognized in income</td><td></td><td>260</td><td>-154</td><td>-123</td></tr><tr><td>Realized (losses) gains</td><td></td><td>-133</td><td>-114</td><td>64</td></tr><tr><td>Net derivative gains (losses)</td><td></td><td>$127</td><td>$-268</td><td>$-59</td></tr></table>
<table><tr><td></td><td colspan="7">Twelve months ended December 31,</td></tr><tr><td></td><td>2016</td><td>2015</td><td>2014</td><td colspan="2">2016 v. 2015</td><td colspan="2">2015 v. 2014</td></tr><tr><td></td><td colspan="7">(in millions, except as noted)</td></tr><tr><td>Net sales</td><td>$1,196</td><td>$1,480</td><td>$1,670</td><td>$-284</td><td>-19%</td><td>$-190</td><td>-11%</td></tr><tr><td>Cost of sales</td><td>920</td><td>955</td><td>998</td><td>-35</td><td>-4%</td><td>-43</td><td>-4%</td></tr><tr><td>Gross margin</td><td>$276</td><td>$525</td><td>$672</td><td>$-249</td><td>-47%</td><td>$-147</td><td>-22%</td></tr><tr><td>Gross margin percentage</td><td>23.1%</td><td>35.5%</td><td>40.3%</td><td>-12.4%</td><td></td><td>-4.8%</td><td></td></tr><tr><td>Sales volume by product tons (000s)</td><td>6,681</td><td>5,865</td><td>6,092</td><td>816</td><td>14%</td><td>-227</td><td>-4%</td></tr><tr><td>Sales volume by nutrient tons (000s)<sup>(1)</sup></td><td>2,109</td><td>1,854</td><td>1,925</td><td>255</td><td>14%</td><td>-71</td><td>-4%</td></tr><tr><td>Average selling price per product ton</td><td>$179</td><td>$252</td><td>$274</td><td>$-73</td><td>-29%</td><td>$-22</td><td>-8%</td></tr><tr><td>Average selling price per nutrient ton<sup>-1</sup></td><td>$567</td><td>$798</td><td>$867</td><td>$-231</td><td>-29%</td><td>$-69</td><td>-8%</td></tr><tr><td>Gross margin per product ton</td><td>$41</td><td>$90</td><td>$110</td><td>$-49</td><td>-54%</td><td>$-20</td><td>-18%</td></tr><tr><td>Gross margin per nutrient ton<sup>-1</sup></td><td>$131</td><td>$283</td><td>$349</td><td>$-152</td><td>-54%</td><td>$-66</td><td>-19%</td></tr><tr><td>Depreciation and amortization</td><td>$247</td><td>$192</td><td>$179</td><td>$55</td><td>29%</td><td>$13</td><td>7%</td></tr><tr><td>Unrealized net mark-to-market loss (gain) on natural gas derivatives</td><td>$-81</td><td>$73</td><td>$30</td><td>$-154</td><td>N/M</td><td>$43</td><td>143%</td></tr></table>
<table><tr><td>(In millions)</td><td>2015 Budget</td><td>Percent of Total</td></tr><tr><td>North America E&P</td><td>$2,885</td><td>82%</td></tr><tr><td>International E&P</td><td>536</td><td>15%</td></tr><tr><td>Oil Sands Mining<sup>(a)</sup></td><td>21</td><td>1%</td></tr><tr><td>Segment total</td><td>3,442</td><td>98%</td></tr><tr><td>Corporate and other</td><td>79</td><td>2%</td></tr><tr><td>Total capital, investment and exploration spending budget</td><td>$3,521</td><td>100%</td></tr></table>

Question: what percentage of the board of directors approved budget was capital expenditures?
Answer: 0.97143
Reasoning program: divide(3.4,3.5)