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FILED: NEW YORK COUNTY CLERK 08/12/ :57 PM INDEX NO /2016 NYSCEF DOC. NO. 13 RECEIVED NYSCEF: 08/12/2016 EXHIBIT 5

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From: David Elliman <delliman@elmcap.com>

Sent: Wednesday, June23, 2010 11:33AM

To: Whalen, Brian [ICG-CMO]

Subject: Waterford 3 2010 appraisal report Attachments: Waterford 3 Report (051 91 0).pdf

As discussed

Original Message ---

From: David Rode [mailto:drode@daimc.com] Sent: Wednesday, May 19, 2010 11:06AM

To: David Elliman

Cc: Alex Dreisbach; Steve Dean

Subject: Waterford 3 appraisal report

David,

Attached, please find our appraisal report for the Waterford 3 facility.

Our conclusions are based on the same assumptions used for the Palo Verde and Perry reports, although updated to

reflectthe May ist valuation date instead of 12/31 . Starting with the 12/31/10 valuation reportfor Waterford 3, which we

will delivery with the other reports next February, we will also decompose the year-over-year valuation changes in the same manner as we have with Palo Verde and Perry.

As always, if you have any questions, please dont hesitate to contact us

Regards,

David C. Rode

Managing Director

DAI Management Consultants, Inc.

(y) 412-220-8920 x204

(f) 41 2-220-8925

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DAll

MANAGEMENT CONSULTANTS May 19, 2010 Mr. David Elliman Chairman Eimrock Capital 150 East 52nd St. New York, NY 10022

RE: May 1, 2010

Valuation

Analysis of the

Waterford

3

Nuclear Generating Station

Dear Mr. Elliman:

In response to a request by Elmrock Capital ("Elmrock"), DAI Management Consultants, Inc.

("DAI") is providing this valuation analysis of Unit 3 of the Waterford Nuclear Generating Station ("Waterford 3"), located in Killona, Louisiana. As part of the scope of this analysis, we have:

1 . Reviewed our previous reports, as well as the current market, economic, and

regulatory conditions that may impact the value of Waterford 3.

2. Provided a brief review and update of operational, economic, and regulatory developments for Waterford 3, highlighting issues deemed material to its value.

3. Determined revenues for Waterford 3 on the basis of wholesale power market prices. Operating expenses were estimated on the basis of actual historical expenses and expected future operation.

4. Determined an indicator of Waterford 3 ' s value using the income capitalization

approach and a valuation date of May 1 , 2010. The income capitalization value of

Waterford 3 was determined on an enterprise value basis using after-tax free cash

flows to equity.

5. Estimated the Fair Market Residual Value ("FMRV") of Waterford 3 as of the end of

the base lease term using a valuation date of July 1, 2017.

DAI Management Consultants, Inc.

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Having completed our analysis with an effective date of May 1 , 20 10, DAI has determined that

the estimated fair market value of Waterford 3, based on the income capitalization approach alone is $2.049 billion ($1,7711kw) as of May 1, 2010. Additionally, the FMRV of Waterford 3

as of the end of the base lease term (July 1, 2017) is $3.224 billion ($2,7871kw) in nominal dollars. Values for future years can be found in Exhibit 8.

Further detail on the valuation is provided below and the pro forma cash flow statement is

provided as Attachment 1 . Limiting conditions and assumptions not otherwise stated in the body

of this letter are contained in Attachment 2.

Details of Facility

Waterford 3 is the third unit of the Waterford Steam Electric Generating Station. The other two units at the Waterford site are natural gas-fired units. As shown in Exhibit 1, the facility is

located on a 3,000 acre site in Killona, Louisiana. Waterford 3 was licensed in March 1985 and entered commercial operation in September of the same year. The facility is wholly owned by Entergy Louisiana, Inc. ("Entergy Louisiana") and operated by Entergy Nuclear.

Exhibit

1:

Waterford

3

Nuclear Generating Station

-.---

g

Waterford 3 is comprised of a Combustion Engineering two-loop pressurized water reactor. The

facility's steam turbine generator was manufactured by Westinghouse. Currently, Waterford 3's

capacity is 1 , 1 57 MW and no power uprates are currently scheduled.' The facility' s operating

license currently expires on December 18, 2024. Entergy Louisiana has announced that it

anticipates submission of a license renewal application for Waterford 3 in January 2013.

Although Entergy Louisiana has not yet submitted an application for extension of the operating license, DAI expects that it will eventually apply for, and receive, a twenty-year license extension, ending at the end of 2044. As a result, DAI' s estimate of the value of Waterford 3 is

based on an economic useful life of sixty years. As of May 1, 2010, the remaining economic

i

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Mr. David Elliman Eimrock Capital May 19, 2010 Page 3 of 15

useful life of the facility is estimated to be slightly greater than thirty-five years, through December 18, 2044.

At Waterford 3's most recent NRC inspection, reported for the first quarter of 2010, the plant received zero findings 2

Production and Revenue

Like most nuclear power generating facilities, Waterford 3 ' s production has remained relatively

stable over time, with the only interruptions being for normal refueling and maintenance outages. Exhibit 2 illustrates the historical annual production of Waterford 3 (average within-year performance reflecting seasonal routine maintenance outages is illustrated in Exhibit 3). On the

whole, Waterford 3 operates as a very reliable baseload generator. Based on historical performance, DAI has estimated a long-run average capacity factor for Waterford 3 of 92.0%.

Exhibit

2:

Historical Annual Production

12,000,000 10,000,000 8,000,000 6,000,000 4,000,000 2,000,000 O

N1MI1kI11I

IflM

III

II II II

liii

II II

III

IllIllIllIllIll

11111

IllIllIllIllIll

11111

IllIllIllIllIll

11111

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

2

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Exhibit

3: Average Monthly

Production

900,000 800,000 700,000 600,000 500,000 400,000 300,000 200,000 100,000 O

Waterford 3 will receive energy prices reflecting the market dynamics within the SERC-Entergy

subregion, which has historically been characterized by the presence of large amounts of natural gas-fired capacity.3 In fact, over 70% of the region's installed capacity of 44,000 MW is

comprised of natural gas-fired combined cycle, combustion turbine, and (older) steam boiler units. Although the region also boasts about 6,000 MW of coal-fired and 5,000 MW of nuclear

capacity, annual peak demand of 28,000 MW implies that the marginal generator in SERC-

Entergy is typically a natural gas-fired unit. As a result, energy prices in SERC-Entergy are

largely driven by natural gas prices.

As Exhibit 4 illustrates, natural gas prices have fallen to historically low levels due to the expanded production from shale gas plays and depressed demand stemming from the economic

3

To be clear, while Entergy Louisiana is a regulated entity, the Waterford 3 lessors are not. Further, Entergy

Louisiana' s regulated assets are the retained interest in Waterford 3 and the lessee' s position in Waterford 3 ; it is

those assets that are subject to ratemaking. The lessor' s undivided interest is only indirectly part of the rate base. In

particular, upon termination of the base lease term, two events are possible: (1) the lease is renewed, or (2) ownership reverts to the lessor. If the lease is renewed by Entergy Louisiana for service to their regulated rate base, the lease payments (under a FMV renewal option) would be evaluated by the LPSC for their "just and

reasonableness" in comparison to then-available alternative supply sources. We assumed that "just and reasonable"

would (as in many other jurisdictions) correspond to prices produced by a competitive market. Similarly, if the

lessor assumed ownership, operation by the lessor as a stand-alone entity or sale of the power back to Entergy Louisiana would still be done on a competitive basis. We do not believe that the lessor would be entitled to a direct claim on ratepayer revenues in the same fashion as Entergy would receive in their franchise operations. Similarly, rate regulation would typically prohibit a third party from receiving the benefit of a capital investment pass-through (such as for the steam generator replacements). Although Entergy Louisiana may in fact pass through certain allowable costs to ratepayers, to the extent that such costs were incurred for capital improvements that increased book value, any removal of the underlying assets would require the return to ratepayers of those reimbursements for the portion intended to be outside of regulation. Accordingly, DAI has valued Waterford 3 from the perspective of

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Mr. David Elliman Eimrock Capital May 19, 2010 Page 5 of 15

recession. The resulting decline in natural gas prices contributed to a steady fall in energy prices

as well. It is important to note that this decrease in energy prices does not reflect a deteriorating

competitive position for power generators on the dispatch hierarchy. As Exhibit 5 illustrates, the

SERC-Entergy system marginal heat rate has remained relatively stable over the last several years and remains very low compared to other regions of the country. Thus, the lower power prices reflect only the "pass-through" of lower natural gas prices.

Exhibit

4:

Natural

Gas

and Energy Prices

in

SERC-Entergy

$140 $120 $100 ';_ $80

I:

$20 so SERC-Entergy Peak SERC-Entergy Off-Peak Henry Hub (left axis)

jan-06 jan-07 jan-08 jan-09

$25 $20 $15 $10 $5 $0 jan-iO

Exhibit

5: System

Marginal Heat Rates

in

SERC-Entergy

20,000 17,500 " 15,000 !_ 12,500 ) 10,000 7,500 5,000 2,500 O

..-

li

1uI________________-I

I

i-

-

---.iír.iaO-

- -

I

í

- -.-4

I'i'!

jan-06 jan-07 jan-08 jan-09 jan-10

SERC, as a whole, remains years away from a system-wide capacity equilibrium and cunently

has a low system marginal heat rate relative to other regions of the country. Over time, however,

as the economy recovers and energy demand growth returns, the substantial excess capacity in

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increase. DAI expects that natural gas-fired capacity will continue to play a dominant role in the region and set energy prices over the long-term.

The economic recovery will also impact the demand for (and price of) natural gas. Looking forward, NYMEX futures prices suggest that natural gas prices will steadily increase towards $6/MMbtu in the near term. The projected expansion of shale gas will likely offset falling production from conventional sources. As a result, shale gas production costs should act as a

ceiling to natural gas prices. For now, the low production costs, extensive domestic availability, and absence of substantial transportation constraints for unconventional gas seem to indicate that natural gas prices will rarely exceed $7/MMbtu. However, this "ceiling" may be more tenuous that it appears, given that limitations on water usage and, even more controversially, wastewater disposal, may restrict the long-term potential of shale gas. DAI believes that shale gas will become an inframarginal supply source in the long-term because of these constraints and,

thereby, marginal natural gas pricing will revert to LNG-derived levels that are several dollars higher per MMbtu.

Based on the expected market trends and projection of natural gas prices, DAI' s forecast of

energy prices is shown in Exhibit 6, which indicates that the real cost of energy in SERC- Entergy is expected to increase over the long-run. The energy price forecast is provided in

nominal dollars, assuming an annual escalation rate of 2.5%.

Exhibit

6:

SERC-Entergy

Average

Energy Price

Historical and Projected

$160 $140 $120 , $100 $80 $60 $20 $0 2006 2009 2012 2015 2018 2021 2024 2027 2030 2033 2036 2039 2042

Perhaps the largest uncertainty looming over the electric power industry as a whole is federal carbon legislation and its projected impact on energy prices . Several legislative bills have been

proposed over the passed several years. To date, only one such proposal has come close to

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Mr. David Elliman Eimrock Capital May 19, 2010 Page 7 of 15

other reasons. Recently, a more restrictive congressional proposal, known as the American Clean Energy and Security Act ("ACES"), was introduced and passed by the House.

Similar to the L-W bill, ACES proposed a cap-and-trade ("CAT") program with an initial allocation of CO2 allowances to CO2-emitting sources. Under ACES, CO2 emission caps would

be placed upstream on petroleum and natural gas and downstream on coal facilities and the

industrial sector.4'5 The bill also permitted the use of domestic offsets and international credits

and provided bonus allowances for carbon capture and storage. The bill required a 17%

reduction in CO2 emissions, from 2005 levels, by 2020 with a target reduction percentage of

83% by 2050.6

In the end, ACES was delayed in the Senate and is now considered dead. Unlike the L-W Bill, however, there was no strong-commodity cycle to deter ACES from passing and its failure appears to have been a consequence of being too aggressive. Although both bills ultimately failed, their failures for different reasons led many industry participants to believe that carbon regulation through legislation will eventually come to fruition. There is broad agreement that a

legislated solution will be far preferable to the Environmental Protection Agency' s ("EPA' s")

application of the Clean Air Act to CO2. Indeed, the EPA itself is struggling with adapting the Clean Air Act for CO2.7 DAI believes legislation in the form of the more moderate L-W Bill is a

more politically feasible solution and therefore we use it as a model for future CO2 legislation. Regardless of the implementation details, any effective CO2 regulation is expected to increase the operating costs for fossil fuel-fired facilities. As a result, these costs will be passed through

to consumers via energy price increases . Because the marginal fuel for the majority of the year is

natural gas, any carbon component in marginal generation costs (and energy prices) will likely be larger during peak periods. Specifically, the peak marginal unit (a combustion turbine unit) burns more natural gas and, therefore, emits more carbon than an off-peak marginal unit (a

combined cycle unit) . As a result, combined cycle units will be able to recover a larger portion of

4

Upstream policies target the carbon content of fuels towards the beginning of the energy supply chain, whereas

downstream controls focus on carbon emissions from combusting fuel at the end of the energy supply chain.

5

The upstream policies also target importers or manufacturers of F-gases (e.g. , sulfur hexafluoride,

perfiourocarbon, hydroflourocarbon ) and nitrous oxide.

6

The different GHGs targeted under ACES (e.g. , F-gases, nitrous oxide) are converted to CO2-equivalents.

7

Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule. U.S. Environmental

Protection Agency proposed rule 4 1 CFR 5 1 , 52, 70, and 7 1 . We note that the use of a so-called "tailoring rule" is

not permitted by the plain text of the Clean Air Act. Rather, the EPA is relying on a legal concept called the "absurd

results doctrine" to permit the deviation, suggesting that the original legislation was not necessarily well-suited for application to CO2. Indeed, in Sturges y. Crowninshield (17 U.S. 122, 202-03 (1819)), ChiefJustice Marshall wrote that "[I]f, in any case, the plain meaning of a provision, not contradicted by any other provision in the same instrument, is to be disregarded, because we believe the framers of that instrument could not intend what they say, it must be one in which the absurdity and injustice of applying the provision to the case, would be so monstrous, that all mankind would, without hesitation, unite in rejecting the application." The U.S. Supreme Court, therefore, in Sturges set a very high bar for disregarding statutory language. We may suppose, then, that the EPA believes that the use of the Clean Air Act to regulate CO2 "would be so monstrous that all mankind would [ . . . ] unite in rejecting

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the carbon penalty relative to combustion turbines. Based on similar logic, new (more efficient) units will be better positioned to recover carbon penalties relative to older units within the same generation class.

Operating Expenses

DAI' s estimate of Waterford 3 ' s operating expenses was derived from actual historical operating

expenses for most categories . All operations and routine maintenance expenses were derived

from historical data as reported to the Federal Energy Regulatory Commission by the plant over

the period 1 999 to 2008 . Operations and routine expenses are expected to be roughly $1 31MWh

in 2010.

Major maintenance expenses for Waterford 3 are based on industry data for similar nuclear generation facilities throughout the country. For the purpose of forecasting future major maintenance, the industry data has been aggregated and placed into dollar per MW terms to be applied to Waterford 3 . The forecasted annual major maintenance total for Waterford 3, as of

May 1, 2010, is roughly $52.5 million. This figure has been escalated annually for future years. Waterford 3 ' s capital expenditures are estimated separately. Specifically, this includes Entergy

Louisiana's plans to replace Waterford 3's steam generators in 2011. In addition to the

replacement of the steam generators, Entergy Louisiana also plans to replace the facility' s

reactor ves sel closure head and control element drive mechanisms . The total cost to complete the

entire scope of work is estimated to be $5 1 1 million. This cost has been amortized over three

years (2010-2012) sunounding the outage.8

There are two major items requiring further discussion in Waterford 3' s operating expenses: fuel

cycle expenses and decommissioning fund contributions. Surging global interest in nuclear power has contributed to a substantial increase in uranium ore prices over the past several years (see Exhibit 7). Although current prices have retreated somewhat from recent record levels, sustained global interest

-

and recent efforts by utilities to restart nuclear development activity

-

suggests that uranium prices can be expected to remain at relatively elevated levels for the foreseeable future.

8

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Mr. David Elliman Eimrock Capital May 19, 2010 Page 9 of 15 $160 $140 $120 $100 $80 $60 $40 $20 $0

Exhibit

7:

Historical

U308 (Spot) Prices

1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

Although the passage of time may have rendered this comparison less than perfect, uranium ore

prices reached into the mid-$40/lb range in the 1970s during the last major building boom in

nuclear power. Today, the industry is faced with not only a growing interest in nuclear generation, but also serious challenges in sourcing and supply. Many of the country' s uranium

mines and processing facilities have been mothballed or retired over the past twenty years as

demand declined. Additionally, generators have been able to "free ride" off of the dismantling of

U.S. and Russian nuclear weapons stockpiles for processed uranium. These stockpiles, however,

are almost depleted and the industry will soon be forced to return to mined sources.

These demands have caused the price of uranium ore to triple over the past several years. However, all nuclear power plants procure their fuel cycle components (ore, processing, enrichment, fabrication) through long-term contracts, so the impact of very high spot prices is

only realized over time. Nevertheless, Waterford 3 may have to rely increasingly on more expensive sources of uranium as their long-term contracts expire over the life of the project. However, nuclear fuel costs remain a very small portion of the overall expense of operating a

nuclear power plant. Nuclear generators such as Waterford 3 are expected to remain extremely competitive on a variable cost basis.

DAI' s estimate of future decommissioning costs is based on the latest available status report

filed with the NRC.9 The report estimates the total cost (in 2008 dollars) of decommissioning

Waterford 3 would be $400.5 million. Based on typical inflation assumptions regarding

decommissioning costs and a real rate of return on accumulated decommissioning funds, Waterford 3 ' s annual decommissioning expense is approximately $6 .6 million.

9

Entergy Louisiana, Inc. Status of Decommissioning Funding for Year Ending December 3 1 , 2008

-

i O CFR

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Additionally, DAI has included a $11MWh expense for spent fuel disposal. The Nuclear Waste Policy Act of 1982, as amended in 1987, required the Department of Energy ("DOE") to begin accepting spent fuel from nuclear power plants for secure disposal. In return for this service, the

DOE began collecting 1 mill/kwh ($11MWh) from generators. The DOE intended to store the

spent fuel in Yucca Mountain, but litigation and construction delays caused the DOE to default

on accepting deliveries . A Federal Court required the DOE to begin accepting deliveries in 1998,

but the DOE defaulted on this delivery date as well. As a result of these continued delays, generators have been forced to incur additional expenses in order to store waste on site or in

other repositories.

Many generators subsequently sued the Federal government to recover the cost of these activities , and thus far court decisions have favored them

i'°

DAI has maintained the

contractual $11MWh charge for disposal on the assumption that companies will continue to

prevail in forcing the Federal government to honor the existing contract for disposal costs. Determination of Value

DAI has elected to use the enterprise valuation methodology for the Income Capitalization Approach. The total value of an "enterprise" or project is the value held by each entity that has a

claim on the project (e.g. , debt and equity). By valuing each component separately, the benefits

of various tax shields and credits, common to many power-generation projects, are made explicit. The enterprise value approach is also known as the free cash flows-to-equity approach because the calculation results in the project' s free cash flow available for distribution to equity

holders."

In determining the appropriate discount rate for Waterford 3, DAI used the current investment grade U.S. corporate bond yield to determine the cost of debt and relied on the widely-used Capital Asset Pricing Model ("CAPM") to estimate the cost of equity. The parameters of this

model are the riskless rate of return (the yield on long-term U.S. Treasury bonds), the market risk premium, and 12

10

Several utilities (including some of the largest nuclear operators, such as Exelon and APS) have settled litigation with the DOE that resulted in the DOE agreeing to reimburse them for any expenses they incurred in storing spent fuel pending the DOE' s fulfillment of its contractual obligations.

i i

See R. Brealey and S. Myers, Principles of Corporate Finance, 7th Edition (Boston, MA: McGraw-Hill, 2003): Chapter 19. The FCFE approach is also discussed as the "enterprise model" in T. Copeland, T. Koller, and J.

Munin, Valuation: Measuring and Managing the Value of Companies, 3ìd Edition (New York, NY: John Wiley,

2000).

12

We use 30-year U.S. Treasury bonds as the proxy for the riskless rate of return. The yield-to-maturity of the 30- year U.S. Treasury bond as of May 2010 is 4.47%. Our estimate of the market risk premium, 7.5%, is taken from S. Kaplan and R. Ruback, "The Valuation of Cash Flow Forecasts: An Empirical Analysis," Journal of Finance 50

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Mr. David Elliman Eimrock Capital May 19, 2010 Page 11 of 15

Beta is a measure of the relative riskiness of the project's cash flows. We derive the forward- looking equity beta by starting with the asset beta, corrected for cash, determined by Value Line for a group of independent power producers and non-regulated generators ( /3A - 0.69 ). We

apply the Hamada adjustment to transform the asset beta into the appropriate equity beta using

the project's capital structure parameters.'3 Finally, we apply the Blume adjustment to

conect

for

the mean-regressing tendency observed in betas.'4 Using the forward-conected equity beta in the

CAPM equation, together with the cunent CAPM parameters, produces an after-tax cost of

equity for the facility of 11.95%, as of May 1, 2010.

The debt-to-capital ratio of Waterford is assumed to be 50%. We have assumed a 20-year debt term with a cost of debt of 6.34%, which reflects typical bonowing costs of investment-grade

bonowers (BBB rated) . In addition, DAI assumes an effective tax rate of 40. 20% for Waterford

3, which reflects federal and state tax rates.'5

Based on an effective date of May 1, 2010 and the estimated revenues, expenses, and cost of

capital discussed above, DAI has determined that the estimated fair market value of Waterford 3,

based on the income capitalization approach alone is $2.049 billion ($ 1

77

1/kw) as of May 1,

2010. Additionally, the FMRV of Waterford 3 as of the end of the base lease term (July 1, 2017)

is $3.224 billion ($2,7871kw) in nominal dollars. Values for future years can be found in

Exhibit 8.

It remains DAI' s distinct pleasure to support Elmrock on this important project. Please contact

me at your convenience should you care to discuss the contents of this letter.

Sincerely,

DAI Management Consultants, Inc.

Steve R. Dean, ASA, P.E.

Managing Principal

Attachment: 1 ) Waterford 3 Income Capitalization Cash Flow Model

2) Legal Notice, Limiting Conditions, and Assumptions

'3

R. Hamada, "Portfolio Analysis, Market Equilibrium and Corporate Finance," Journal ofFinance 24 (1969): 13

31.

'4

M. Blume, "Betas and Their Regression Tendencies," Journal ofFinance 30 (1975): 785-795.

15

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Exhibit

8:

Waterford

3

Future

Value Table December 31, 2010 December 31, 2011 December 31, 2012 December 31, 2013 December 31, 2014 December 31, 2015 December 31, 2016 December 31, 2017 December 31, 2018 December 31, 2019 December 31, 2020 December 31, 2021 December 31, 2022 December 31, 2023 December 31, 2024 December 31, 2025 December 31, 2026 December 31, 2027 December 31, 2028 December 31, 2029 December 31, 2030 December 31, 2031 December 31, 2032 December 31, 2033 December 31, 2034 December 31, 2035 December 31, 2036 December 31, 2037 December 31, 2038 December 31, 2039 December 31, 2040 December 31, 2041 December 31, 2042 December 31, 2043 December 31, 2044

Nominal Dollars 2009 Dollars

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Waterford 3 Cash Flow May 1, 2010 . Capacy Factor 92 04% 634% Co%ofEqaoy 11 95% ICo%ofDth DthOCapOaI 5004% Effc0vTa Ra% 40 20%

-

CapacOy (MW)

-

CapacOy

o

ra0o (MWO)

-

Ergy Pnc Total Orating OprathgFxpaa

99Iar Fa& Cyc% Epa

-

Urniam, M04044s, dP cssg

-

ToW Fa& Cyc%

OW ra0os ,

Ro%rn Major Maoroaoc

MojoMoiotr000cr

Strom Go orrotor Rrplocrmrro Toral Major Maoroaoc Ma roralrao a Srrpphor Proporry Tao

.

Total Oparatiarg Eanaaa NatøparatingCaahFlow

EartarlarioaVala.a s 1,940,170,195 Io,r,al Dolor Balaoco S 970,005,090

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1,157 1,157 1,157 1,157 1,157 1,157 1,157 1,157 1,157 1,157 1,157 1,157 1,157 1,157 1,157 1,157 92% 92% 92% 92% 92% 92% 92% 92% 92% 92% 92% 92% 92% 92% 92% 92% 9,320,390 9,328,390 9,320,390 9,328,390 9,320,390 9,320,390 9,328,3W 9,320,390 9,328,390 9,320,390 9,328,3W 9,320,390 9,320,390 9,320,390 9,320,390 9,320,390 s 36 14 $ 4478 $ 52 23 $ 55.40 $ 57 74 $ 60 30 $ 6259 $ 63 90 $ 6503 $ 67 01 $ 70 45 $ 73 65 $ 76 47 $ 70 00 $ 77 30 $ 7090 s 337,1 60,544 s 417,760493 $ 407,217,769 $ 51 6,768,817 $ 530,610,079 $ 562,536,016 $ 503.093,025 $ 596,1 1 1 090 $ 606,657ß82 $ 632,550,070 $ 657,210,940 $ 607,000,606 $ 71 3,321 471 $ 727,613,555 $ 721,1 12,491 $ 736,030,551 s 337,160,544 $ 417,760,493 $ 487,217,769 $ 516,768,817 $ 538,610,079 $ 562,536,816 $ 583,893,025 $ 596,111,890 $ 606,657,682 $ 632,550,878 $ 657,210,940 $ 687,008,686 $ 713,321,471 $ 727,613,555 $ 721,112,491 $ 736,038,551 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 s 78,484,48 $ 76,384,392 $ 77,547,428 $ 79,089,721 $ 80,848,975 $ 87,419,150 $ 89,558,800 $ 91,949,842 $ 94,6O836 $ 97,128,109 $ 99,501,671 $ 102,150,575 $ 14,868,O9O $ 107,655,959 $ 110,515,965 $ 117,255,388 s 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 $ 9,328,390 s 6,644,139 $ 6,644,139 $ 6644,139 $ 6,644,139 $ 6,644,139 $ 6,644,139 $ 6,644,139 $ 6,644,139 $ 6,644,139 $ 6,644,139 $ 6,644,139 $ 6,644,139 $ 6,644,139 $ 44,J39 $ 6,644,139 $ 6,644,139 s 94,456,577 s 92,356,921 $ 93,519,957 $ 95,062,250 $ 96,021 505 $ 103,391 600 $ 105,531 329 $ 107,922,371 $ I 10,579,365 $ I I 3,100,630 $ I I 5,474,201 $ I I 0,1 23,105 $ 120,040,620 $ 123,62L40 $ 126,400,494 $ 133,227,917 s 47,421 470 $ 40,607,015 $ 49,822,1 91 $ 51,067,745 $ 52,344,439 $ 53,653,050 $ 54,994,376 $ 56,369,236 $ 57,770,467 $ 59,222,920 $ 60,703,501 $ 62,221 009 $ 63,776,616 $ 65,371 032 $ 67,005,307 $ 60,600,440 s 46,,21 6 s 47,970,422 $ 49,177002 $ 50,407,329 $ 51,667,513 $ 52,959,200 $ 54,203,1 00 $ 55,640,260 $ 57,031 266 $ 50,457,040 $ 59,910,474 $ 61,416,436 $ 62,951 047 $ 64.525,643 $ 66,1 30,704 $ 67,792,254 s 52,550,069 s 53863,821 $ 55,2/0,416 $ 56,590,676 $ 58,005,443 $ 59,455,579 $ 60,941,969 $ 62,465,518 $ 64,022156 $ 65,622835 $ 67,268,531 $ 68,95244 $ 70,674,000 $ 7Z,44O,50 $ 74,251,872 $ 76,108,168 s 170,333,333 s 170,333,333 $ 170,333333 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - s 222,883,402 s 224197,154 $ 225,543,749 $ 56,590,676 $ 50,005,443 $ 59,455,579 $ 60,941,969 $ 62,465,510 $ 64,027,156 $ 65,627,035 $ 67,260,531 $ 68.950244 $ 70,674,000 $ 72,440,050 $ 74,251,072 $ 76,100,160 s 21542.066 s 22,000,610 $ 22,632,6v $ 23,190,449 $ 23,770,411 $ 24,372,071 $ 24,902,193 $ 25,606,747 $ 26,246,916 $ 26,903,009 $ 27,575,666 $ 28,265.050 $ 20,971,604 $ 29,695,976 $ 30,430,376 $ 31,199,335 s 3371 605 s 3,455,096 $ 3.542293 $ 3,630,050 $ 3,721 622 $ 3,014,662 $ 3,910,029 $ 4,007,779 $ 4,107,974 $ 4,210,673 $ 4,315,940 $ 4,423,39 $ 4,534,434 $ 4,647,795 $ 4,763,990 $ 4,003,090 s 3317,691 s ,79,200 $ 4,372920 $ 4,015,667 $ 4,979,220 $ 5,135,662 $ 5,200,906 $ 5,435,055 $ 5,591,769 $ 5,761,323 $ 5,919,072 $ 6,06L194 s 6,196,997 $ 6,310,209 $ 6,427,155 $ 6,503,942 s 439,801,037 $ 442,555,225 $ 448,611,626 $ 284,772,968 $ 291,318,160 $ 302,782,705 $ 309,932,063 $ 317,447,766 $ 325,362,913 $ 333,283,535 $ 341,176,185 $ 349,467,964 $ 357,946,199 $ 366,620,074 $ 375,513,978 $ 388,475,147 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 s (102,640,493( $ (24,794,732( $ 38,606,143 $ 231,995,850 $ 247,291,919 $ 259,754,111 $ 273,960,963 $ 278,664,124 $ 281,294,769 $ 299,267,343 $ 316,034,755 $ 337,540,721 $ 355,375,272 $ 360,993,482 $ 345,598,513 $ 347,563,404 DbtAmortization 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 DthrThrm I 2 3 4 5 6 7 0 9 10 11 12 13 14 15 16 B grnrur g Prrncpal s 970,005,090 $ 944,660,275 $ 917,639510 $ 000,096,597 $ 058. 0,799 $ 26,519 $ 791,260,010 $ 754,502,960 $ 71 5,413,910 $ 673,845,49 $ 629,641 M $ 382,633,00 $ 532,644,795 $ 479,405,509 $ 422,954.860 $ 361839.030 Iarrn h rrs r s (61.522797) S (59.910,062) $ (58,196,698) $ (56,373,022) $ (5 - QIO) $ (50,101,761) $ (47,050,570) $ (45,371,551) $ (42.735304) $ (39,931,866) $ (35,950,634) $ (33,700,333) $ (30,400,971) $ (26823797) S (23011252) Prrncpal Paymr s (2 -]1 7,020,757) $ (28,742921) $ (30,565,797) $ 5' -. :) -» :; 02) $ (36,757,050) $ (39,009,042) $ (41,560,069) $ (44.204316) $ (47,0a7.753) $ (49,9,985) $ (53,159,206) $ (56,530,640) $ (60.1 1 ' j6S)

Edrng P rrnc pal s 4 -b1'5 $ 917,639,510 $ 088,896597 $ 050,330,799 $ 025826519 $ 791,2J,010 $ 754,502,960 $ 71 5,413,910 $ 673,045,049 $ 629,641 534 $ 582,633700 $ 532,644795 $ 479,405,509 $ 422,954,060 $ 362,039,O3 $ 290,910,671

Dbt Srvi C ovrag Ratio O i O 96 1.30 2 55 2 57 2 59 2 65 2 67 2 67 2 79 2 89 3 02 3 13 3 15 3 03 2 76

s (97,008,510( $ (184,316,169( $ (165,884,552( $ (149,393,105( $ (134,453,795( $ (120,872,603( $ (114,470,042( $ (114,470,042( $ (114,664,059( $ (114,470,042( $ (114,664,059( $ (114,470,042( $ (114,664,059( $ (114,470,042( $ (114,664,059( $ (57,235,021( ITotalDproation hr trs tExpns s (61,522,797( $ (59,910,862( $ (58,196,698( $ (56,373,822( $ (54,435,339( $ (52,373,918( $ (50,181,761( $ (47,850,578( $ (45,371,551( $ (42,735,304( $ (39,931,866( $ (36,950,634( $ (33,780,333( $ (30,408,971( $ (26,823,797( $ (23,011,252( s (261,171,800( $ (269,021,762( $ (185,475,107( $ 26,228,923 $ 58,402,785 $ 86,507,590 $ 109,309,160 $ 116,343,504 $ 121,259,159 $ 142,061,997 $ 161,438,830 $ 186,120,046 $ 206,930,881 $ 216,114,469 $ 204,110,657 $ 267,317,132 INtInom hrom Tax s 104,991,064 $ 108,146,748 $ 74,560,993 $ (10,544,027( $ (23,477,920( $ (34,776,051( $ (43,942,282( $ (46,770,089( $ (48,746,182( $ (57,108,923( $ (64,898,410( $ (74,820,258( $ (83,186,214( $ (86,878,017( $ (82,052,484( $ (107,461,487( After-Tax hrom s (156,180,736( $ (160,875,014( $ (110,914,114( $ 15,684,896 $ 34,924,865 $ 51,731,539 $ 65,366,878 $ 69,573,416 $ 72,512,977 $ 84,953,074 $ 96,540,421 $ 111,299,787 $ 123,744,667 $ 129,236,452 $ 122,058,173 $ 159,855,645 s 97,008,510 $ 184,316,169 $ 165,884,552 $ 149,393,105 $ 134,453,795 $ 120,872,603 $ 114,470,042 $ 114,470,042 $ 114,664,059 $ 114,470,042 $ 114,664,059 $ 114,470,042 $ 114,664,059 $ 114,470,042 $ 114,664,059 $ 57,235,021 ITotalDproation Prinopal s (25,416,822( $ (27,028,757( $ (28,742,921( $ (30,565,797( $ (32,504,280( $ (34,565,702( $ (36,757,858( $ (39,089,042( $ (41,568,069( $ (44,204,316( $ (47,007,753( $ (49,988,985( $ (53,159,286( $ (56,530,648( $ (60,115,822( $ (63,928,368( 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Fr

Cash flow to Equity $ (84,589,049( $ (3,587,603( $ 26,227,517 $ 134,512,204 $ 136,874,380 $ 138,038,441 $ 143,079,061 $ 144,954,415 $ 145,608,967 $ 155,218,800 $ 164,196,726 $ 175,780,844 $ 185,249,439 $ 187,175,846 $ 176,606,410 $ 153,162,298

nmnylFrnflfl.r, NPV of Fr Cash Flows ro Equry

liti

$ 970,085,097 i 2009 dolls

Dthr Vakrn s 970,085,098 i 2009 dolls

E rrprs Vakrn s 1,940,170,195 i2009dolls

1mphd D scorn r Rare From O praru g Cash Flows 11.63%

(iNomilDolls) s 1,771 $ 1,961 $ 2,210 $ 2,434 $ 2,517 $ 2,596 $ 2,673 $ 2,748 $ 2,826 $ 2,912 $ 2,992 $ 3,067 $ 3,132 $ 3,189 $ 3,249 $ 3,328 pns Vakrn (i2010Dolls) $ 2,049,026,331 $ 2,212,527,476 $ 2,432,544,201 $ 2,612,692,238 $ 2,634,732,138 $ 2,650,412,945 $ 2,662,147,833 $ 2,668,518,541 $ 2,677,282,416 $ 2,690,356,813 $ 2,696,140,767 $ 2,695,456,679 $ 2,684,706,730 $ 2,666,290,348 $ 2,648,619,482 $ 2,646,241,426

(17)
(18)

DAll

MANAGEMENT CONSULTANTS

Attìehmit

Legal Notice

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document solely for the benefit of Elmrock Capital ("Elmrock") . Neither DAI, Elmrock, nor any

person acting on their behalf, including any party contributing to it: (a) makes any wananty,

express or implied, with respect to the use of any information or methods disclosed in this report; and (b) assumes any liability with respect to the use of any information or methods disclosed in this report.

Any recipient of this report, by their receipt and use of this report, hereby releases Elmrock and DAI from any liability for direct, indirect, or consequential loss or damage, whether arising in

contract, tort (including negligence), strict liability or otherwise.

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and

Assumptions

In addition to the assumptions stated explicitly in the body of the letter report, provided below is a summary of additional limiting conditions and assumptions associated with this report.

i . All related facts, comments, and data set forth herein have been obtained from sources

believed to be knowledgeable, reliable, and accurate.

2. DAI assumes no responsibility for changes in market conditions or for the inability of the

project participants to obtain prices at the forecasted values.

3. The material in this letter report reflects DAI' s best professional judgment in light of the

information provided and/or available at the time of preparation. Accordingly, DAI accepts no responsibility for decisions made or actions taken based upon this report. This

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approval of DAI.

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