commodities purchased for use in our supply chain.
We manage our exposures through a combination of purchase orders, long-term contracts with suppliers, exchange-traded futures and options, and over-the-counter options and swaps.
We offset our exposures based on current and projected market conditions and generally seek to acquire the inputs at as close to our planned cost as possible.
We use derivatives to manage our exposure to changes in commodity prices.
We do not perform the assessments required to achieve hedge accounting for commodity derivative positions.
Accordingly, the changes in the values of these derivatives are recorded currently in cost of sales in our Consolidated Statements of Earnings.
Although we do not meet the criteria for cash flow hedge accounting, we believe that these instruments are effective in achieving our objective of providing certainty in the future price of commodities purchased for use in our supply chain.
Accordingly, for purposes of measuring segment operating performance these gains and losses are reported in unallocated corporate items outside of segment operating results until such time that the exposure we are managing affects earnings.
At that time we reclassify the gain or loss from unallocated corporate items to segment operating profit, allowing our operating segments to realize the economic effects of the derivative without experiencing any resulting mark-to-market volatility, which remains in unallocated corporate items.
Unallocated corporate items for fiscal 2019, 2018 and 2017 included:
## Table 0 ##
As of May 26, 2019, the net notional value of commodity derivatives was $312.5 million, of which $242.9 million related to agricultural inputs and $69.6 million related to energy inputs.
These contracts relate to inputs that generally will be utilized within the next 12 months.
INTEREST RATE RISK We are exposed to interest rate volatility with regard to future issuances of fixed-rate debt, and existing and future issuances of floating-rate debt.
Primary exposures include U. S.  Treasury rates, LIBOR, Euribor, and commercial paper rates in the United States and Europe.
We use interest rate swaps, forward-starting interest rate swaps, and treasury locks to hedge our exposure to interest rate changes, to reduce the volatility of our financing costs, and to achieve a desired proportion of fixed rate versus floating-rate debt, based on current and projected market conditions.
Generally under these swaps, we agree with a counterparty to exchange the difference between fixed-rate and floating-rate interest amounts based on an agreed upon notional principal amount.
Floating Interest Rate Exposures — Floating-to-fixed interest rate swaps are accounted for as cash flow hedges, as are all hedges of forecasted issuances of debt.
Effectiveness is assessed based on either the perfectly effective hypothetical derivative method or changes in the present value of interest payments on the underlying debt.
Effective gains and losses deferred to AOCI are reclassified into earnings over the life of the associated debt.
Ineffective gains and losses are recorded as net interest.
The amount of hedge ineffectiveness was less than $1 million in fiscal 2019, a $2.6 million loss in fiscal 2018, and less than $1 million in fiscal 2017.
Fixed Interest Rate Exposures — Fixed-to-floating interest rate swaps are accounted for as fair value hedges with effectiveness assessed based on changes in the fair value of the underlying debt and derivatives, using
considered a derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of SFAS 133.
As of December 31, 2007, based on the Company’s stock price, the redemption value of this embedded derivative was approximately $87 million.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity Variable interest in Equity investments — As of December 31, 2007, NRG had not entered into any financing structure that was designed to be off-balance sheet that would create liquidity, financing or incremental market risk or credit risk to the Company.
However, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting.
NRG’s pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $122 million as of December 31, 2007.
This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.
Synthetic Letter of Credit Facility and Revolver Facility — Under NRG’s amended Senior Credit Facility which the company entered in to on June 8, 2007, the Company has a $1.3 billion synthetic Letter of Credit Facility which is secured by a $1.3 billion cash deposit at Deutsche Bank AG, New York Branch, the Issuing Bank.
This deposit was funded using proceeds from the Term B loan investors who participated in the facility syndication.
Under the Synthetic Letter of Credit Facility, NRG is allowed to issue letters of credit for general corporate purposes including posting collateral to support the Company’s commercial operations activities.
On August 6, 2007, NRG entered into an agreement with BNP Paribas, or BNP, whereby BNP has agreed to be an issuing bank under the revolver portion of the Company’s Senior Credit Facility.
BNP has agreed to issue up to $350 million of letters of credit.
In addition, on January 30, 2008, NRG entered into an agreement with Bank of America, whereby Bank of America has also agreed to be an issuing bank under the revolver portion of the Company’s Senior Credit Facility.
Bank of America has agreed to issue up to $250 million of letters of credit under the revolver.
This increases the amount of unfunded letters of credit the Company can issue under its Revolving Credit Facility to $900 million for ongoing working capital requirements and for general corporate purposes, including acquisitions that are permitted under the Senior Credit Facility.
In addition, NRG is permitted to issue additional letters of credit of up $100 million under the Senior Credit facility through other financial institutions.
As of December 31, 2007, the Company had issued $743 million in letters of credit under the Synthetic Letter of Credit Facility.
In addition, as of December 31, 2007, the Company had issued $3 million in letters of credit under the Revolving Credit Facility.
A portion of these letters of credit supports non-commercial letter of credit obligations.
Contractual Obligations and Commercial Commitments NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company’s capital expenditure programs.
The following tables summarize NRG’s contractual obligations and guarantees.
For an additional discussion, see Item 15 — Note 11, Debt and Capital Leases, and Note 21, Commitments and Contingencies, to the Consolidated Financial Statements.
## Table 1 ##
(a) Includes only those coal transportation commitments for 2008 as no other nominations were made as of December 31, 2007.
The following table summarizes NRG's U. S.  coal capacity and the corresponding revenues and average natural gas prices and positions resulting from coal hedge agreements extending beyond December 31, 2015, and through 2019 for the East region:
## Table 2 ##
(a) Net coal capacity represents nominal summer net MW capacity of power generated as adjusted for the Company's ownership position excluding capacity from inactive/mothballed units, see Item 2 - Properties for units scheduled to be deactivated.
(b) Forecasted generation dispatch output (MWh) based on forward price curves as of December 31, 2015, which is then divided by number of hours in a given year to arrive at MW capacity.
The dispatch takes into account planned and unplanned outage assumptions.
(c) Includes amounts under power sales contracts and natural gas hedges.
The forward natural gas quantities are reflected in equivalent MWh based on forward market implied heat rate as of December 31, 2015, and then combined with power sales to arrive at equivalent MWh hedged which is then divided by number of hours in a given year to arrive at MW hedged.
The coal sales include swaps and delta of options sold which is subject to change.
For detailed information on the Company's hedging methodology through use of derivative instruments, see discussion in Item 15 - Note 5, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements.
Includes inter-segment sales from the Company's wholesale power generation business to the retail business.
(d) Percentage hedged is based on total coal sales as described in (c) above divided by the forecasted coal capacity.
(e) Represents U. S.  coal sales, including energy revenue and demand charges, excluding revenues derived from capacity auctions.
Capacity and Other Contracted Revenue Sources NRG's revenues and cash flows benefit from capacity/demand payments and other contracted revenue sources, originating from market clearing capacity prices, Resource Adequacy contracts, tolling arrangements, PPAs and other long-term contractual arrangements: ?
Capacity auctions — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO.
Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time performance, where NRG's actual revenues will be the combination of revenues based on the cleared auction MWs plus the net of any over- and under-performance of NRG's fleet.
PJM integrated a new Capacity Performance product into the market in 2015, as further described in Regulatory Matters.
In addition, MISO has an annual auction, known as the Planning Resource Auction, or PRA.
The Gulf Coast assets situated in the MISO market may participate in this auction.
In certain circumstances, capacity from the Gulf Coast region may be sold into the PJM market.  ?
Resource Adequacy and bilateral contracts — In California, there is a resource adequacy requirement mandated by law that is satisfied through bilateral contracts.
The Company's newer generation in California is contracted under longterm tolling agreements.
Certain other sites in California have short-term tolling agreements or resource adequacy contracts.
In addition, NRG earns demand payments from its long-term full-requirements load contracts with nine Louisiana distribution cooperatives, which expire in 2025.
Demand payments from the current long-term contracts are tied to summer peak demand and provide a mechanism for recovering a portion of the costs associated with new or changed environmental laws or regulations.
In Texas, capacity and contracted revenues are through bilateral contracts with load serving entities.  ?
Long-term PPAs — Output from the majority of renewable energy assets and certain conventional energy plants is sold through long-term PPAs and tolling agreements to a single counterparty, which is often a utility or commercial customer.

Tables referenced above, in order (Table 0 first):
<table><tr><td></td><td>Fiscal Year</td></tr><tr><td>In Millions</td><td>2019</td><td>2018</td><td>2017</td></tr><tr><td>Net gain (loss) onmark-to-marketvaluation of commodity positions</td><td>$-39.0</td><td>$14.3</td><td>$-22.0</td></tr><tr><td>Net loss on commodity positions reclassified from unallocated corporate items to segmentoperating profit</td><td>10.0</td><td>11.3</td><td>32.0</td></tr><tr><td>Netmark-to-marketrevaluation of certain grain inventories</td><td>-7.0</td><td>6.5</td><td>3.9</td></tr><tr><td>Netmark-to-marketvaluation of certain commodity positions recognized in unallocated corporate items</td><td>$-36.0</td><td>$32.1</td><td>$13.9</td></tr></table>
<table><tr><td></td><td colspan="6"> By Remaining Maturity at December 31,</td></tr><tr><td></td><td colspan="5"> 2007</td><td></td></tr><tr><td></td><td> Under </td><td></td><td></td><td> Over </td><td></td><td> 2006 </td></tr><tr><td> Contractual Cash Obligations</td><td> 1 Year</td><td> 1-3 Years</td><td> 3-5 Years</td><td> 5 Years</td><td> Total</td><td> Total</td></tr><tr><td></td><td colspan="6"> (In millions)</td></tr><tr><td>Long-term debt (including estimated interest)</td><td>$1,010</td><td>$1,407</td><td>$1,263</td><td>$8,621</td><td>$12,301</td><td>$13,348</td></tr><tr><td>Capital lease obligations (including estimated interest)</td><td>93</td><td>66</td><td>28</td><td>203</td><td>390</td><td>403</td></tr><tr><td>Operating leases</td><td>40</td><td>73</td><td>64</td><td>243</td><td>420</td><td>427</td></tr><tr><td>Fuel purchase and transportation obligations<sup>(a)</sup></td><td>1,614</td><td>1,059</td><td>299</td><td>231</td><td>3,203</td><td>3,646</td></tr><tr><td>Total contractual cash obligations</td><td>$2,757</td><td>$2,605</td><td>$1,654</td><td>$9,298</td><td>$16,314</td><td>$17,824</td></tr></table>
<table><tr><td>East</td><td>2016</td><td>2017</td><td>2018</td><td>2019</td><td>AnnualAverage for2016-2019</td></tr><tr><td></td><td colspan="5">(Dollars in millions unless otherwise stated)</td></tr><tr><td>Net Coal Capacity (MW)<sup>(a)</sup></td><td>8,295</td><td>7,472</td><td>7,472</td><td>6,256</td><td>7,374</td></tr><tr><td>Forecasted Coal Capacity (MW)<sup>(b)</sup></td><td>4,250</td><td>3,568</td><td>2,873</td><td>2,235</td><td>3,232</td></tr><tr><td>Total Coal Sales (MW)<sup>(c)</sup></td><td>4,056</td><td>2,021</td><td>422</td><td>5</td><td>1,626</td></tr><tr><td>Percentage Coal Capacity Sold Forward<sup>(d)</sup></td><td>95%</td><td>57%</td><td>15%</td><td>—%</td><td>42%</td></tr><tr><td>Total Forward Hedged Revenues<sup>(e)</sup></td><td>$1,554</td><td>$726</td><td>$117</td><td>$2</td><td></td></tr><tr><td>Weighted Average Hedged Price ($ per MWh)<sup>(e)</sup></td><td>$43.63</td><td>$41.01</td><td>$31.58</td><td>$41.03</td><td></td></tr><tr><td>Average Equivalent Natural Gas Price ($ per MMBtu)<sup>(e)</sup></td><td>$3.03</td><td>$3.02</td><td>$2.87</td><td>$3.27</td><td></td></tr><tr><td>Gas Price Sensitivity Up $0.50/MMBtu on Coal Units</td><td>$93</td><td>$200</td><td>$264</td><td>$220</td><td></td></tr><tr><td>Gas Price Sensitivity Down $0.50/MMBtu on Coal Units</td><td>$-38</td><td>$-140</td><td>$-183</td><td>$-149</td><td></td></tr><tr><td>Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal Units</td><td>$41</td><td>$88</td><td>$128</td><td>$121</td><td></td></tr><tr><td>Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal Units</td><td>$-31</td><td>$-73</td><td>$-94</td><td>$-88</td><td></td></tr></table>

Question: Which year is Forecasted Coal Capacity greater than 3500 ?
Answer: 2016 2017