Working Capital
## Table 0 ##
The increase in accounts receivable was primarily the result of higher product shipments in the final month of the fourth quarter of fiscal 2015 as compared to the final month of the fourth quarter of fiscal 2014.
Overall, our days in sales outstanding remained consistent year-over-year.
Inventory as of October 31, 2015 increased as compared to the end of the fourth quarter of fiscal 2014 primarily as a result of increased manufacturing production to support anticipated higher sales demand.
Our inventory levels are impacted by our need to support forecasted sales demand and variations between those forecasts and actual demand.
Days cost of sales in inventory increased from 115 days at the end of the fourth quarter of fiscal 2014 to 121 days at the end of fiscal 2015 as a result of recognizing approximately $53.6 million of additional cost related to the sale of acquired inventory written up to fair value as a result of the Acquisition in fiscal 2014.
Current liabilities increased to $1.1 billion at October 31, 2015 from $709.1 million recorded at the end of fiscal 2014.
The increase was primarily the result of the classification of our $375.0 million aggregate principal amount of 3.0% senior unsecured notes due April 15, 2016 as current and, to a lesser extent, increases in accounts payable, deferred income on shipments to distributors as more fully described below and accrued liabilities.
These increases were partially offset by decreases in income taxes payable.
As of October 31, 2015 and November 1, 2014, we had gross deferred revenue of $379.9 million and $349.7 million, respectively, and gross deferred cost of sales of $79.8 million and $71.3 million, respectively.
Deferred income on shipments to distributors increased in fiscal 2015 primarily as a result of higher demand for products sold into the channel.
Sales to distributors are made under agreements that allow distributors to receive price-adjustment credits and to return qualifying products for credit, as determined by us, in order to reduce the amounts of slow-moving, discontinued or obsolete product from their inventory.
Given the uncertainties associated with the levels of price-adjustment credits to be granted to distributors, the sales price to the distributors is not fixed or determinable until the distributors resell the products to their customers.
Therefore, we defer revenue recognition from sales to distributors until the distributors have sold the products to their customers.
The amount of price-adjustments is dependent on future overall market conditions, and therefore the levels of these adjustments could fluctuate significantly from period to period.
To the extent that we experience a significant increase in the amount of credits we issue to our distributors, there could be a material impact on the ultimate revenue and gross margin recognized relating to these transactions.
Debt As of October 31, 2015, we had $873.3 million of carrying value outstanding on our debt.
The difference in the carrying value of the debt and the principal amount of the debt is due to the unamortized discount on these instruments that will accrete to the face value of the debt over the term of the debt.
Our debt obligations consist of the following: $375.0 million aggregate principal amount of 3.0% senior unsecured notes On April 4, 2011, we issued $375.0 million aggregate principal amount of 3.0% senior unsecured notes due April 15, 2016 (the 2016 Notes) with semi-annual fixed interest payments due on April 15 and October 15 of each year, commencing October 15, 2011.
$500.0 million aggregate principal amount of 2.875% senior unsecured notes On June 3, 2013, we issued $500.0 million aggregate principal amount of 2.875% senior unsecured notes due June 1, 2023 (the 2023 Notes) with semi-annual fixed interest payments due on June 1 and December 1 of each year, commencing December 1, 2013.
The indentures governing the 2016 Notes and the 2023 Notes contain covenants that may limit our ability to: incur, create, assume or guarantee any debt for borrowed money secured by a lien upon a principal property; enter into sale and leaseback transactions with respect to a principal property; and consolidate with or merge into, or transfer or lease all or substantially all of our assets to, any other party.
As of October 31, 2015, we were compliant with these covenants.
See Note 16
31, 2015, the price was R$218/MWh.
After the expiration of contract with Eletropaulo, Tietê's strategy is to contract most of its physical guarantee, as described in Regulatory Framework section below, and sell the remaining portion in the spot market.
Tietê's strategy is reassessed from time to time according to changes in market conditions, hydrology and other factors.
Tietê has been continuously selling its available energy from 2016 forward through medium-term bilateral contracts of three to five years.
As of December 31, 2016, Tietê's contracted portfolio position is 95% and 88% with average prices of R$157/ MWh and R$159/MWh (inflation adjusted until December 2016) for 2016 and 2017, respectively.
As Brazil is mostly a hydro-based country with energy prices highly tied to the hydrological situation, the deterioration of the hydrology since the beginning of 2014 caused an increase in energy prices going forward.
Tietê is closely monitoring and analyzing system supply conditions to support energy commercialization decisions.
Under the concession agreement, Tietê has an obligation to increase its capacity by 15%.
Tietê, as well as other concession generators, have not yet met this requirement due to regulatory, environmental, hydrological and fuel constraints.
The state of S?o Paulo does not have a sufficient potential for wind power and only has a small remaining potential for hydro projects.
As such, the capacity increases in the state will mostly be derived from thermal gas capacity projects.
Due to the highly complex process to obtain an environmental license for coal projects, Tietê decided to fulfill its obligation with gas-fired projects in line with the federal government plans.
Petrobras refuses to supply natural gas and to offer capacity in its pipelines and regasification terminals.
Therefore, there are no regulations for natural gas swaps in place, and it is unfeasible to bring natural gas to AES Tietê.
A legal case has been initiated by the state of S?o Paulo requiring the investment to be performed.
Tietê is in the process of analyzing options to meet the obligation.
Uruguaiana is a 640 MW gas-fired combined cycle power plant located in the town of Uruguaiana in the state of Rio Grande do Sul, commissioned in December 2000.  AES manages and has a 46% economic interest in the plant with the remaining interest held by BNDES.
The plant's operations were suspended in April 2009 due to the unavailability of gas.
AES has evaluated several alternatives to bring gas supply on a competitive basis to Uruguaiana.
One of the challenges is the capacity restrictions on the Argentinean pipeline, especially during the winter season when gas demand in Argentina is very high.
The plant operated on a short-term basis during February and March 2013, March through May 2014, and February through May 2015 due to the short-term supply of LNG for the facility.
The plant did not operate in 2016.
Uruguaiana continues to work toward securing gas on a long-term basis.
Market Structure — Brazil has installed capacity of 150,136 MW, which is 65% hydroelectric, 19% thermal and 16% renewable (biomass and wind).
Brazil's national grid is divided into four subsystems.
Tietê is in the Southeast and Uruguaiana is in the South subsystems of the national grid.
Regulatory Framework — In Brazil, the Ministry of Mines and Energy determines the maximum amount of energy that a plant can sell, called physical guarantee, which represents the long-term average expected energy production of the plant.
Under current rules, physical guarantee can be sold to distribution companies through longterm regulated auctions or under unregulated bilateral contracts with large consumers or energy trading companies.
The National System Operator ("ONS") is responsible for coordinating and controlling the operation of the national grid.
The ONS dispatches generators based on hydrological conditions, reservoir levels, electricity demand and the prices of fuel and thermal generation.
Given the importance of hydro generation in the country, the ONS sometimes reduces dispatch of hydro facilities and increases dispatch of thermal facilities to protect reservoir levels in the system.
In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels.
A mechanism known as the Energy Reallocation Mechanism ("MRE") was created to share hydrological risk across MRE hydro generators.
If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may need to purchase energy in the short-term market to fulfill their contract obligations.
When total hydro generation is higher than the total MRE physical guarantee, the surplus is proportionally shared among its participants and they are able to make extra revenue selling the excess energy on the spot market.
The consequences of unfavorable hydrology are (i) thermal plants more expensive to the system being dispatched, (ii) lower hydropower generation with deficits in the MRE and (iii) high spot prices.
ANEEL defines the spot price cap for electricity in the Brazilian market.
The spot price caps as defined by ANEEL and average spot prices by calendar year are as follows (R$/ MWh):
## Table 1 ##
PRUDENTIAL FINANCIAL, INC.  Notes to Consolidated Financial Statements 22.
SEGMENT INFORMATION (continued)
## Table 2 ##
d $24,875 million and revenues from foreign operations of $10,122 million, $10,393 million and $9,502 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Included in the revenues from foreign operations are revenues from Japanese operations of $8,587 million, $7,814 million and $6,702 million and revenues from Korean operations of $1,247 million, $1,417 million and $1,720 million for the years ended December 31, 2009, 2008 and 2007, respectively The Asset Management segment revenues include intersegment revenues of $347 million, $348 million and $363 million for the years ended December 31, 2009, 2008 and 2007, respectively, primarily consisting of asset-based management and administration fees.
Management has determined the intersegment revenues with reference to market rates.
Intersegment revenues are eliminated in consolidation in Corporate and Other.

<table><tr><td></td><td colspan="2">Fiscal Year</td><td></td><td></td></tr><tr><td></td><td>2015</td><td>2014</td><td>$ Change</td><td>% Change</td></tr><tr><td>Accounts Receivable</td><td>$466,527</td><td>$396,605</td><td>$69,922</td><td>18%</td></tr><tr><td>Days Sales Outstanding</td><td>46</td><td>46</td><td></td><td></td></tr><tr><td>Inventory</td><td>$412,314</td><td>$367,927</td><td>$44,387</td><td>12%</td></tr><tr><td>Days Cost of Sales in Inventory</td><td>121</td><td>115</td><td></td><td></td></tr></table>
<table><tr><td>Year</td><td>2017</td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Spot price cap as defined by ANEEL</td><td>534</td><td>423</td><td>388</td><td>822</td></tr><tr><td>Average spot rate</td><td></td><td>94</td><td>287</td><td>689</td></tr></table>
<table><tr><td></td><td colspan="7">Year ended December 31, 2007</td></tr><tr><td></td><td>Revenues</td><td> Net Investment Income</td><td>Policyholders’ Benefits</td><td>Interest Credited to Policyholders’ Account Balances</td><td> Dividends to Policyholders’</td><td> Interest Expense</td><td>Amortization of Deferred Policy Acquisition Costs</td></tr><tr><td></td><td colspan="7">(in millions)</td></tr><tr><td>Financial Services Businesses:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Individual Annuities</td><td>$2,503</td><td>$580</td><td>$211</td><td>$359</td><td>$—</td><td>$59</td><td>$285</td></tr><tr><td>Retirement</td><td>4,708</td><td>3,676</td><td>1,145</td><td>2,073</td><td>—</td><td>212</td><td>18</td></tr><tr><td>Asset Management</td><td>2,319</td><td>216</td><td>—</td><td>—</td><td>—</td><td>62</td><td>20</td></tr><tr><td>Total U.S. Retirement Solutions and Investment Management Division</td><td>9,530</td><td>4,472</td><td>1,356</td><td>2,432</td><td>—</td><td>333</td><td>323</td></tr><tr><td>Individual Life</td><td>2,602</td><td>656</td><td>881</td><td>218</td><td>23</td><td>165</td><td>164</td></tr><tr><td>Group Insurance</td><td>4,799</td><td>671</td><td>3,623</td><td>240</td><td>—</td><td>8</td><td>9</td></tr><tr><td>Total U.S. Individual Life and Group Insurance Division</td><td>7,401</td><td>1,327</td><td>4,504</td><td>458</td><td>23</td><td>173</td><td>173</td></tr><tr><td>International Insurance</td><td>8,258</td><td>1,608</td><td>4,831</td><td>330</td><td>76</td><td>13</td><td>486</td></tr><tr><td>International Investments</td><td>745</td><td>34</td><td>—</td><td>—</td><td>—</td><td>6</td><td>—</td></tr><tr><td>Total International Insurance and Investments Division</td><td>9,003</td><td>1,642</td><td>4,831</td><td>330</td><td>76</td><td>19</td><td>486</td></tr><tr><td>Corporate Operations</td><td>239</td><td>735</td><td>39</td><td>-126</td><td>—</td><td>662</td><td>-47</td></tr><tr><td>Real Estate and Relocation Services</td><td>291</td><td>24</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total Corporate and Other</td><td>530</td><td>759</td><td>39</td><td>-126</td><td>—</td><td>662</td><td>-47</td></tr><tr><td>Total</td><td>26,464</td><td>8,200</td><td>10,730</td><td>3,094</td><td>99</td><td>1,187</td><td>935</td></tr><tr><td>Reconciling items:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Realized investment gains (losses), net, and related adjustments</td><td>-41</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Charges related to realized investment gains (losses), net</td><td>9</td><td>—</td><td>1</td><td>2</td><td>73</td><td>—</td><td>-15</td></tr><tr><td>Investment gains (losses) on trading account assets supporting insurance liabilities, net</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Change in experience-rated contractholder liabilities due to assets value changes</td><td>—</td><td>—</td><td>—</td><td>-13</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Divested businesses</td><td>364</td><td>26</td><td>-3</td><td>—</td><td>—</td><td>1</td><td>—</td></tr><tr><td>Equity in earnings of operating joint ventures and earnings attributable to noncontrolling interests</td><td>-400</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total Financial Services Businesses</td><td>26,396</td><td>8,226</td><td>10,728</td><td>3,083</td><td>172</td><td>1,188</td><td>920</td></tr><tr><td>Closed Block Business</td><td>7,981</td><td>3,789</td><td>4,021</td><td>139</td><td>2,731</td><td>257</td><td>76</td></tr><tr><td>Total per Consolidated Financial Statements</td><td>$34,377</td><td>$12,015</td><td>$14,749</td><td>$3,222</td><td>$2,903</td><td>$1,445</td><td>$996</td></tr></table>

Question: what was the percentage change in the average spot rate between 2014 to 2015?
Answer: -0.58345