Income Taxes The effective income tax rate was 38.3% in fiscal 2006, 38.8% in fiscal 2005, and 38.5% in fiscal 2004.
The fiscal 2006 decrease resulted primarily from a legal entity reorganization in the fourth quarter of fiscal 2005.
The company created a centralized corporate management entity in an effort to obtain operational, legal, and other benefits that also resulted in state tax efficiencies.
The fiscal 2005 increase resulted from geographic expansion into states with higher income tax rates, including having a larger percentage of stores located in unitary tax states.
OPERATIONS OUTLOOK Store Openings and Capital Expenditures During the fiscal year ending February 28, 2007, we plan to expand our used car superstore base by approximately 16%, opening approximately 11 used car superstores, consisting of an approximately equal mix of standard and satellite superstores.
FISCAL 2007 PLANNED SUPERSTORE OPENINGS
## Table 0 ##
(1) Part of the Washington, D. C.  television market.
We expect to open approximately four stores in the first quarter of fiscal 2007, two stores late in the third quarter, and five stores in the fourth quarter.
Given their timing, we expect little, if any, contribution to fiscal 2007 sales and profits from the stores scheduled to open in the fourth quarter.
In addition, normal construction, permitting, or other scheduling delays could shift the opening dates of any of these stores into fiscal 2008.
With an estimated television viewing population of approximately 185,000, Charlottesville, Va. , represents our first entry into a small market.
We will be adjusting our store footprint, inventory, and our staffing model in this store, as a result of the smaller overall sales opportunities provided by this market.
This store’s performance over the next few years will help us better understand our longer-term opportunities in small markets.
In May 2006, we opened our first “CarMax Car Buying Center,” which is in the Atlanta market in a major automotive retail center not currently served by CarMax.
The store is staffed with CarMax buyers, who conduct appraisals and purchase vehicles on site using the same processes and systems utilized in our used car superstores.
We do not sell cars at this store.
This test store is part of our long-term program to increase both appraisal traffic and retail vehicle sourcing self-sufficiency.
We estimate gross capital expenditures will total approximately $300 million in fiscal 2007.
Planned expenditures primarily relate to new store construction and land purchases associated with future year store openings.
Compared with fiscal 2006, the increase in estimated fiscal 2007 capital spending primarily reflects a higher level of real estate purchases for store development in future years, as well as the timing of construction activities.
constraints that impact the delivery of fuel into the region.
In this environment, NRG seeks both to enhance its ability to be the low cost wholesale generator capable of delivering wholesale power to load centers within the region from multiple locations using multiple fuel sources, and to be properly compensated for delivering such wholesale power and related services.
The generation performance by fuel-type for the recent three-year period is as shown below:
## Table 1 ##
NRG’s Northeast region assets are located in or near load centers and inside chronic transmission constraints such as New York City, Southwest Connecticut and the Delmarva Peninsula.
Assets in these areas tend to attract higher capacity revenues and higher energy revenues and thus present opportunities for repowering these sites.
The Company seeks to enhance the value of these sites primarily through the advocacy of capacity market reforms that better reflect their locational value.
Over the past year, the Company has benefited from the introduction of more robust capacity market reforms in both the New England Power Pool, or NEPOOL, and PJM.
The Locational Forward Reserve Markets, or LFRM, in the NEPOOL, was effective October 1, 2006, and the transition capacity payments were effective December 1, 2006 with an initial price of $3.05/kw month.
In all three LFRM auctions to date, the market has cleared at the administratively set price of $14/kw month reflecting the shortage of peaking generation especially in the Connecticut zone.
These relatively new markets serve as a prelude to the full implementation of the Forward Capacity Market, or FCM, which begins June 1, 2010, and for which the first auction was conducted in February 2008.
PJM’s reliability pricing model, or RPM, was effective June 1, 2007 and the Company has participated in auctions providing capacity price certainty through May 2011.
RMR Agreements — Several of the Northeast region’s Connecticut assets are located in transmission-constrained load pockets and have been designated as required to be available to ISO-NE to ensure reliability.
These assets are subject to reliability must-run, or RMR, agreements, which are contracts under which NRG agrees to maintain its facilities to be available to run when needed, and are paid to provide these capability services based on the Company’s costs.
During 2007, Middletown and Montville were covered by an RMR agreement.
Unless terminated earlier, these agreements will terminate on June 1, 2010 which coincides with the commencement of the FCM in NEPOOL.
On July 16, 2007, FERC conditionally accepted, subject to refund, the Company’s RMR filing for its Norwalk plant.
This RMR was retroactive to June 19, 2007, which coincides with the FERC decision to eliminate PUSH bidding.
The Company is engaged in settlement discussions with FERC to determine the actual value of the RMR payment this plant should receive.
In the recently-concluded FCM auction for delivery year 2010/ 2011, the Company sought to de-list Norwalk’s units 1 and 2.
ISO-NE declined to accept that de-list bid on the grounds these units were needed for reliability.
Norwalk will likely operate pursuant to an RMR agreement after June 1, 2010.
Generation Facilities As of December 31, 2007, NRG’s generation facilities in the Northeast region consisted of approximately 6,980 MW of generation capacity, including assets located in transmission constrained areas, such as New York City — 1,415 MW, and Southwest Connecticut — 535 MW.
The following table summarizes NRG's global generation portfolio as of December 31, 2017:
## Table 2 ##
(a) All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis.
MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.
(b) GenOn, which represented 16,423 MW of global generation at December 31, 2016, was deconsolidated from NRG for financial reporting purposes on June 14, 2017.
(c) Includes International.
(d) Includes Distributed Solar capacity from assets held by DGPV Holdco 1, DGPV Holdco 2 and DGPV Holdco 3.
(e) Does not include NRG Yield, Inc. 's thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.
(f) The Distributed Solar figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems.
Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco.
(g) Natural gas generation does not include 51 MW related to the Miramar and El Cajon sites which were part of the San Diego Combustion Turbines and retired on January 1, 2017, 106 MW related to Encina Unit 1 which was deactivated on March 31, 2017 and 371 MWs related to Greens Bayou 5 which was mothballed on May 29, 2017 following ERCOT's termination of the RMR agreement.
Greens Bayou 5 was retired in January 2018.
(h) In 2017 and 2018, NRG sold 111 and 10 MWs, respectively, to third parties related to certain Minnesota wind assets.
(i) NRG Yield's total generation capacity includes 6 MWs for noncontrolling interest for Spring Canyon II and III.
NRG Yield's total generation capacity net of this noncontrolling interest was 5,241 MWs.
(j) On February 6, 2018, NRG announced the sale of its South Central business, which owns and operates a 3,555 MW portfolio of generation assets in Gulf Coast.
NRG will lease back the 1,263 MW Cottonwood facility.
(k) On February 6, 2018, NRG announced the sale of its full ownership in NRG Yield, Inc.  and its Renewables operating and development platform, which represents 3,440 MW.
NRG's portfolio diversification and commercial operations hedging strategy provides the Company with reliable future cash flows.
NRG has hedged a portion of its coal and nuclear capacity with decreasing hedge levels through 2021.
In addition, NRG's capacity revenues not only enhance the reliability of future cash flows but are not correlated to natural gas prices.
As of December 31, 2017, the Company had purchased fuel forward under fixed price contracts, with contractually-specified price escalators, for approximately 41% of its expected coal requirement from 2018 to 2021.
The Company enters into additional hedges when it believes market conditions are favorable.
The Company also has the advantage of being able to supply its retail businesses with its own generation, which can reduce the need to sell and buy power from other institutions and intermediaries, resulting in lower transaction costs and credit exposures.
This combination of generation and retail allows for a reduction in actual and contingent collateral, through offsetting transactions and by reducing the need to hedge the retail power supply through third parties.
The generation and retail combination also provides stability in cash flows, as changes in commodity prices generally have offsetting impacts between the two businesses.
The offsetting nature of generation and retail, in relation to changes in market prices, is an integral part of NRG's goal of providing a reliable source of future cash flow for the Company.
When developing new renewable and conventional power generation facilities, NRG typically secures long-term PPAs, which insulate the Company from commodity market volatility and provide future cash flow stability.
These PPAs are typically contracted with high credit quality local utilities and typically have durations from 10 years to as much as 25 years.
Commercial Operations Overview NRG seeks to maximize profitability and manage cash flow volatility through the marketing, trading and sale of energy, capacity and ancillary services into spot, intermediate and long-term markets and through the active management and trading of emissions allowances, fuel supplies and transportation-related services.
The Company's principal objectives are the realization of the full market value of its asset base, including the capture of its extrinsic value, the management and mitigation of commodity market risk and the reduction of cash flow volatility over time.
NRG enters into power sales and hedging arrangements via a wide range of products and contracts, including PPAs, fuel supply contracts, capacity auctions, natural gas derivative instruments and other financial instruments.
In addition, because changes in power prices in the markets where NRG operates are generally correlated to changes in natural gas prices, NRG uses hedging strategies that may include power and natural gas forward sales contracts to manage the commodity price risk primarily associated with the Company's coal and nuclear generation assets.
The objective of these hedging strategies is to stabilize the cash flow generated by NRG's portfolio of assets.
In addition to power sales and hedging arrangements, NRG trades electric power, natural gas and related commodity and financial products, including forwards, futures, options and swaps.
The Company seeks to generate profits from volatility in the price of electricity, capacity, fuels and transmission congestion by buying and selling contracts in wholesale markets under guidelines approved by the Company's risk management committee.
Coal and Nuclear Operations The following table summarizes NRG's U. S.  coal and nuclear capacity and the corresponding revenues and average natural gas prices and positions resulting from coal and nuclear hedge agreements extending beyond December 31, 2017, and through 2021 for the Company's Gulf Coast region:
## Table 3 ##
(a) Net coal and nuclear capacity represents nominal summer net MW capacity of power generated as adjusted for the Company's current 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, 2017, 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 GWh based on forward market implied heat rate as of December 31, 2017, and then combined with power sales to arrive at equivalent GWh hedged.
The coal and nuclear 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 and nuclear sales as described in (c) above divided by the forecasted coal and nuclear capacity.
(e) Represents U. S.  coal and nuclear sales, including energy revenue and demand charges.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) on historical trends and known economic and market conditions at the time of valuation.
Actual results may differ substantially from these assumptions.
These differences may significantly impact future pension or retiree medical expenses.
Annual pension and retiree medical expense is principally the sum of three components: 1) increase in liability from interest; less 2) expected return on plan assets; and 3) other gains and losses as described below.
The expected return on plan assets is calculated by applying an assumed long-term rate of return to the fair value of plan assets.
In any given year, actual returns can differ significantly from the expected return.
Differences between the actual and expected return on plan assets are combined with gains or losses resulting from the revaluation of plan liabilities.
Plan liabilities are revalued annually, based on updated assumptions and information about the individuals covered by the plan.
The combined gain or loss is generally expensed evenly over the remaining years that employees are expected to work.
Comprehensive Income (Loss) The Company accounts for comprehensive income (loss) in accordance with the provisions of SFAS No.130, “Reporting Comprehensive Income” (“SFAS No.130”).
SFAS No.130 is a financial statement presentation standard that requires the Company to disclose non-owner changes included in equity but not included in net income or loss.
Other items of comprehensive income (loss) presented in the financial statements consists of adjustments to the Company’s minimum pension liability as follows (in thousands):

<table><tr><td></td><td></td><td> Standard Superstores</td><td> Satellite Superstores</td><td> Total Superstores</td></tr><tr><td>Hartford / New Haven, Conn.</td><td>New mid-sized market</td><td>1</td><td>1</td><td>2</td></tr><tr><td>Columbus, Ohio</td><td>New mid-sized market</td><td>1</td><td>1</td><td>2</td></tr><tr><td>Oklahoma City, Okla.</td><td>New mid-sized market</td><td>1</td><td>—</td><td>1</td></tr><tr><td>Los Angeles, Calif.</td><td>Existing large market</td><td>—</td><td>1</td><td>1</td></tr><tr><td>Charlottesville, Va.</td><td>New small market</td><td>—</td><td>1</td><td>1</td></tr><tr><td>Fredericksburg, Va.<i><sup>-1</sup></i></td><td>Existing large market</td><td>1</td><td>—</td><td>1</td></tr><tr><td>Austin, Tex.</td><td>Existing mid-sized market</td><td>—</td><td>1</td><td>1</td></tr><tr><td>Charlotte, N.C.</td><td>Existing mid-sized market</td><td>1</td><td>—</td><td>1</td></tr><tr><td>Fresno, Calif.</td><td>New mid-sized market</td><td>1</td><td>—</td><td>1</td></tr><tr><td>Total planned openings</td><td></td><td>6</td><td>5</td><td>11</td></tr></table>
<table><tr><td></td><td colspan="3"> Net Generation</td></tr><tr><td></td><td> 2007</td><td> 2006</td><td> 2005</td></tr><tr><td></td><td colspan="3"> (In thousands of MWh)</td></tr><tr><td>Coal</td><td>11,527</td><td>11,042</td><td>11,363</td></tr><tr><td>Oil</td><td>1,169</td><td>1,217</td><td>3,148</td></tr><tr><td>Gas</td><td>1,467</td><td>1,050</td><td>1,735</td></tr><tr><td>Total</td><td>14,163</td><td>13,309</td><td>16,246</td></tr></table>
<table><tr><td></td><td colspan="6">Global Generation Portfolio<sup>(a)(b)</sup> (In MW)</td></tr><tr><td></td><td colspan="2">Generation</td><td></td><td></td><td></td><td></td></tr><tr><td>Generation Type</td><td>Gulf Coast<sup>(j)</sup></td><td>East/West<sup>(c)</sup></td><td>Renewables<sup>(d)(k)</sup></td><td>NRG Yield<sup>(e)(k)</sup></td><td>Other<sup>(f)(k)</sup></td><td>Total Global</td></tr><tr><td>Natural gas<sup>(g)</sup></td><td>7,464</td><td>4,939</td><td>—</td><td>1,878</td><td>—</td><td>14,281</td></tr><tr><td>Coal</td><td>5,114</td><td>3,870</td><td>—</td><td>—</td><td>—</td><td>8,984</td></tr><tr><td>Oil</td><td>—</td><td>3,642</td><td>—</td><td>190</td><td>—</td><td>3,832</td></tr><tr><td>Nuclear</td><td>1,136</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,136</td></tr><tr><td>Wind<sup>(h)</sup></td><td>—</td><td>—</td><td>648</td><td>2,206</td><td>—</td><td>2,854</td></tr><tr><td>Utility Scale Solar</td><td>—</td><td>—</td><td>738</td><td>921</td><td>—</td><td>1,659</td></tr><tr><td>Distributed Solar</td><td>—</td><td>—</td><td>179</td><td>52</td><td>114</td><td>345</td></tr><tr><td>Total generation capacity<sup>(i)</sup></td><td>13,714</td><td>12,451</td><td>1,565</td><td>5,247</td><td>114</td><td>33,091</td></tr><tr><td>Capacity attributable to noncontrolling interest<sup>(i)</sup></td><td>—</td><td>—</td><td>-685</td><td>-2,359</td><td>—</td><td>-3,044</td></tr><tr><td>Total net generation capacity</td><td>13,714</td><td>12,451</td><td>880</td><td>2,888</td><td>114</td><td>30,047</td></tr></table>
<table><tr><td>Gulf Coast</td><td>2018</td><td>2019</td><td>2020</td><td>2021</td><td>AnnualAverage for2018-2021</td></tr><tr><td></td><td colspan="5">(Dollars in millions unless otherwise stated)</td></tr><tr><td>Net Coal and Nuclear Capacity (MW)<sup>(a)</sup></td><td>6,250</td><td>6,250</td><td>6,250</td><td>6,250</td><td>6,250</td></tr><tr><td>Forecasted Coal and Nuclear Capacity (MW)<sup>(b)</sup></td><td>4,558</td><td>4,402</td><td>4,303</td><td>4,114</td><td>4,344</td></tr><tr><td>Total Coal and Nuclear Sales (GWh)<sup>(c)</sup></td><td>33,394</td><td>8,203</td><td>7,348</td><td>7,977</td><td>14,231</td></tr><tr><td>Percentage Coal and Nuclear Capacity Sold Forward<sup>(d)</sup></td><td>84%</td><td>21%</td><td>19%</td><td>22%</td><td>37%</td></tr><tr><td>Total Forward Hedged Revenues<sup>(e)</sup></td><td>$1,399</td><td>$422</td><td>$399</td><td>$429</td><td>$—</td></tr><tr><td>Weighted Average Hedged Price ($ per MWh)<sup>(e)</sup></td><td>$41.90</td><td>$51.47</td><td>$54.36</td><td>$53.74</td><td>$—</td></tr><tr><td>Average Equivalent Natural Gas Price ($ per MMBtu)<sup>(e)</sup></td><td>$3.17</td><td>$4.47</td><td>$4.79</td><td>$5.01</td><td>$—</td></tr><tr><td>Gross Margin Sensitivities</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gas Price Sensitivity Up $0.50/MMBtu on Coal and Nuclear Units</td><td>$5</td><td>$134</td><td>$136</td><td>$138</td><td>$—</td></tr><tr><td>Gas Price Sensitivity Down $0.50/MMBtu on Coal and Nuclear Units</td><td>$—</td><td>$-150</td><td>$-148</td><td>$-126</td><td>$—</td></tr><tr><td>Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal and Nuclear Units</td><td>$57</td><td>$90</td><td>$94</td><td>$96</td><td>$—</td></tr><tr><td>Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal and Nuclear Units</td><td>$-38</td><td>$-74</td><td>$-78</td><td>$-79</td><td>$—</td></tr></table>

Question: What was the average of Total Forward Hedged Revenues in 2019, 2020, and 2021? (in million)