Financial analysis of the sufficiency of Brattle’s ...

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London Economics International LLC contact:

717 Atlantic Ave, Suite 1A Julia Frayer/ Victor Chung

Boston, MA 02111 Tel: (617) 933-7221

www.londoneconomics.com [email protected]

Financial analysis of the sufficiency of Brattle’s

estimated ATWACC to support investment in a new

merchant peaker in Alberta

prepared by London Economics International LLC

July 6, 2018

Alberta is currently in the process of moving from an energy-only market design to an energy &

capacity market design. London Economics International LLC (“LEI”) was retained by

TransAlta Corporation (“TransAlta”) to review the methodologies proposed by the Brattle

Group (“Brattle”), AESO’s consultant, to estimate the After-tax Weighted Average Cost of

Capital (“ATWACC”) underpinning its Gross Cost of New Entry (“Gross CONE”) calculation.

In this memo, LEI presents quantitative evidence demonstrating that using Brattle’s ATWACC,

the resulting Gross CONE, and other assumptions from AESO, coupled with a more realistic

consideration of the debt structure (as would be required by any financial institution lending to

such a merchant generation project) leads to a lower return on equity for investors than the

expected returns Brattle identified in its justification for the cost of equity. This financial

analysis suggests that the ATWACC estimated by Brattle is too low, and therefore a capacity

price based on this ATWACC and associated Gross CONE would lead to an outcome where

investing in a merchant peaker in Alberta would not be an attractive economic investment.

Table of contents 1 WHY IS PROPER ESTIMATION OF THE CONE VALUE IMPORTANT TO THE CAPACITY MARKET DESIGN? ..... 2

2 OVERVIEW OF BRATTLE’S ATWACC ............................................................................................................... 2

3 FINANCING ASSUMPTIONS IMPLIED IN BRATTLE’S ATWACC CALCULATIONS ARE NOT REALISTIC ......... 3

3.1 THE SIZE OF DEBT SHOULD BE DERIVED USING A TARGET DEBT-SERVICE COVERAGE RATIO FOR THE PROJECT

BASED ON A RANGE OF EXPECTED CASHFLOWS ....................................................................................................... 4 3.2 DEBT HAS TO BE PAID DOWN WITHIN THE LIFETIME OF THE PROJECT ........................................................... 6 3.3 LEI’S PRO FORMA MODEL DEMONSTRATES BRATTLE’S ATWACC IS UNREALISTIC ..................................... 7

3.3.1 Assumptions .......................................................................................................................................... 8 3.3.2 Adding in cash sweep provisions ......................................................................................................... 11 3.3.3 Less ideal market conditions scenario .................................................................................................. 13

4 APPENDIX ........................................................................................................................................................... 15

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1 Why is proper estimation of the CONE value important to the

capacity market design?

The Cost of New Entry (“CONE”) is a key component in capacity market design. The Brattle

Group (“Brattle”) stated that CONE is one of the estimates needed to “anchor” the proposed

capacity market’s sloped demand curve. During the capacity market demand curve design, a

Gross CONE, which aims to reflect the annualized carrying cost of a new generator based on a

reference technology appropriate for Alberta’s market, is first estimated. Then, an Energy and

Ancillary Services (“E&AS”) offset, is subtracted from the Gross CONE to arrive at a Net CONE.

However, Brattle stated that “the Net CONE will not determine the market clearing price of

capacity” (emphasis by Brattle), and “rather the market clearing price will depend on the offers

that suppliers make into the capacity market auction.”1

While Net CONE is not the only determining factor of the capacity market clearing price, it does

have an important impact on the capacity market clearing price. For example:

▪ holding other factors constant (demand forecast, reliability requirement, and supply), changes in Net CONE shift the capacity demand curve and change the point of intersection between the cumulative supply of capacity offers and the demand curve, therefore influencing the capacity clearing price; and,

▪ if the Net CONE is materially lower than the actual cost of a new efficient generator, in the long run the market may not be able to procure the resources it needs to achieve its reliability target, as the capacity clearing price may not be attractive enough for investors to build new generating units.

As such, ATWACC is critical to ensuring that a key desired end-state of AESO’s capacity market

design – new investment by the private sector – is achieved.

2 Overview of Brattle’s ATWACC

The key components of ATWACC relate to the cost of equity, the cost of debt, and the capital

structure or leverage, as illustrated in the formula below:

ATWACC = cost of equity x (1-debt/capital) + (1-tax rate) x cost of debt x (debt/capital)

In the June 14th 2018 Working Group materials, Brattle recommended an ATWACC of 8.0%, for

new generation investment in Alberta, based on the assumptions shown in the table below.

1 AESO. “Cost of New Entry – Preliminary Estimates Selection Criteria, Energy and Ancillary Services Offset DCWG

#4”. June 14, 2018. Slide 7.



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Figure 1. Brattle’s recommendation for Merchant Generation Cost of Capital

Source: AESO. “Cost of new Entry – Preliminary Estimates Selection Criteria. Energy and Ancillary Services Offset.

DCWG #4.” June 14, 2018. Slide 19.

According to Brattle and its presentation in the April and June Working Groups, its approach in

estimating ATWACC is based on the following steps:2

▪ estimate the cost of equity using publicly available data of US and Canadian companies considered comparable with methods such as the Capital Asset Pricing Model (“CAPM”) and Discounted Cash Flow (“DCF”);

▪ use data on cost of debt and debt-to-equity ratio from the same group of comparable companies; and, finally

▪ adjust the ATWACC for: (1) consensus forecast of 2021 Canadian market conditions; (2) yields of 20-year Canadian bonds.

Brattle also referenced discount rates used in fairness opinions in IPP transactions and used these

discount rates as an additional benchmark for their recommended ATWACC.

Brattle stated that it did not consider the details of the actual financing arrangements in

developing its ATWACC. However, the details of the financing are critical to ensuring that the

ATWACC results in a Gross CONE and Net CONE that support investment in Alberta.

3 Financing assumptions implied in Brattle’s ATWACC calculations

are not realistic

LEI undertook a financial analysis that tests whether Brattle’s ATWACC and resulting Gross

CONE – when coupled with realistic financing requirements – can support investors in

generation in Alberta.

Capital structure is implicit in Brattle’s recommendation of an 8.0% fixed ATWACC over the life

of the reference generating unit. However, Brattle’s analysis only goes so far as to assume a

2 AESO. “Cost of new Entry – Preliminary Estimates Selection Criteria. Energy and Ancillary Services Offset. DCWG

#4.” June 14, 2018. Slide 19.



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leverage in the calculations of the ATWACC. To test the sufficiency of Brattle’s ATWACC, LEI

began by creating a pro forma financial model – similar to financial models that lenders would

create and test when considering lending to a project. The financial model starts with Brattle’s

ATWACC assumption and resulting Gross CONE and builds up to an income statement - with

revenues and costs - to estimate the cashflow generated by the project. LEI then added realistic

debt repayment terms.

3.1 The size of debt should be derived using a target debt-service coverage ratio for the

project based on a range of expected cashflows

Brattle developed the level of leverage of the reference technology based on the list of public

sample companies it used to estimate ATWACC. In this list of companies, there are moderately

leveraged Canadian generators and highly leveraged US generators. Using these sample

companies, Brattle assumed the level of debt-to-capital ratio of an Alberta merchant generation

cost of capital to be 50% to 65%. Brattle’s method in estimating ATWACC takes no consideration

of how debt financing would impact the project. In practice, the amount of debt a project can

borrow from banks is not derived from “peer reviews.” Rather, the level, pricing, and other terms

of the debt are typically a function of the earnings potential and revenue stability of the project.

LEI anticipates that the level of debt for peaker in Alberta would be significantly less than what

Brattle forecast if more realistic financing assumptions were incorporated.

Based on LEI’s experience in advising generation investors, as well as more common knowledge

about how merchant (unregulated) generation projects are financed, the key determining factor

for sizing the debt principal is the project’s expected debt service coverage ratio (“DSCR”),

defined as the ratio between the net operating income and debt payments (interest + principal

repayment). The available cash flow from operations is typically not certain and, to limit default

risk, lenders would want to ensure the borrower has enough cashflow cushion to pay its debt

obligations. The maximum size of the debt is therefore based on the level of debt and interest

payments, plus a cushion, that could be supported by such projected cashflows. This approach,

sometimes called “debt sculpting”, ensures that the project can expect to repay its principal and

interest in a timely manner.

Based on LEI’s experience with active lenders in the merchant generation space in North America,

bankers would typically require a DSCR of 2.0x to 3.0x for a merchant generating project.3

Although term loans from banks do not necessary require credit evaluation from credit agencies,

evaluation criteria from credit agencies serve as useful references. For example, Fitch Ratings has

3 Standard debt covenants may require specific levels of DSCR on a monthly, quarterly and/or annual basis. For the

purposes of this illustration, LEI conducted its analysis on an annual basis.



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stated that a full merchant exposure thermal power project with fully amortizing debt would

require an indicative DSCR of 1.8x in order obtain an investment grade BBB rating.4

Standard & Poor’s Project Finance Rating Criteria Reference Guide listed the DSCR as the key

metric in its project finance ratings framework, as presented in the green box in the Figure 2.5

Note that the DSCR is the only metric explicitly shown in the framework.

Figure 2. Standard and Poor’s Project Finance Ratings Framework

Source: Standard & Poor’s. “Standard & Poor’s Project Finance Ratings Criteria – Reference Guide”. September 16,

2014. Page 3.

In addition to DSCR, Standard & Poor’s uses a combination of market risk and operational risk

analysis to determine the credit rating of a project finance loan. For Standard and Poor’s,

merchant power plants are deemed to have moderate operational risk and moderate to high

market exposure. This combination of market and operation risk result in a high operational

4 Fitch Ratings. “Thermal Power Project Rating Criteria – Effective June 8, 2017 – June 1, 2018”. June 8, 2017

5 Standard & Poor’s. Accessible at:

https://www.spratings.com/documents/20184/86990/SPRS_Project%2BFinance%2BRatings%2BCriteria%2B

Reference%2BGuide_FINAL/cdfde690-57d1-4ff4-a87f-986527603c22



https://www.spratings.com/documents/20184/86990/SPRS_Project%2BFinance%2BRatings%2BCriteria%2BReference%2BGuide_FINAL/cdfde690-57d1-4ff4-a87f-986527603c22

https://www.spratings.com/documents/20184/86990/SPRS_Project%2BFinance%2BRatings%2BCriteria%2BReference%2BGuide_FINAL/cdfde690-57d1-4ff4-a87f-986527603c22

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phase business risk,6 leading to a DSCR requirement 2.5x to 5.0x for in order to obtain an

investment grade BBB rating.

In addition, lenders will routinely consider “low revenue” cases or “debt cases” for projected

cashflows in order to understand how the DSCR may vary with uncertain and volatile market

conditions. Although beyond the scope of LEI’s current quantitative exercise, LEI would suggest

that AESO similarly conduct a thorough sensitivity analysis on future potential energy and

capacity revenues for a merchant peaker as part of its rationalization of Brattle’s ATWACC.

3.2 Debt has to be paid down within the lifetime of the project

It is important to remember that the estimation of Gross CONE includes the return on and return

of capital over a specified timeframe. As a physical asset, the reference unit has various

timeframes – there is the “tax” life for purposes of calculating depreciation; there is the financing

term (and associated amortization requirements of the debt principal); there is the engineering

life (timeframe over which the equipment is expected to function without significant

deterioration); and finally there is the economic life (timeframe where the asset has an economic

useful life).

The 20-year assumption commonly used in the US for considering generation assets’ ATWACC

is neither the engineering life or the economic life of the asset, but rather its “tax” life. As is

common in the US, Brattle assumed that the economic life of a merchant generation unit in

Alberta is 20 years.7 Brattle did not tailor this assumption to Alberta’s market or to the different

generation technologies considered.

Brattle also assumed that the capital structure would remain constant throughout this economic

lifetime (as it uses the same ATWACC to discount the CONE over 20 years). This is an unrealistic

assumption, as the debt principal has to be paid down over time. Even though the project could

possibly obtain refinancing over its lifetime, the previous debt would still have to be repaid and

cash has to be set aside for principal repayment reserves. To achieve this pay down of principal,

project finance loans would typically include a cash sweep (or cash flow sweep) provision, under

which excess cash flows must be used to pay down debt. According to S&P, “these sweep

mechanisms can vary materially, both in terms of the percentage of excess cash flow that must be

6 Standard & Poor’s. “Standard & Poor’s Project Finance Ratings Criteria Reference Guide.” Page 145 Table 2 shows

that natural gas fired power stations as operating stability assessment rating of 5 to 6 out of a scale of 10 (lower

benign more stable). Page 157 Table 12 shows that merchant power plants have moderate to high market

exposure depending on level of contract. This combination results in a preliminary Operations Phase Business

Assessment score of 10 to 11, according to Table 1 in page 141.

7 AESO. “Cost of New Entry – Preliminary Estimates Selection Criteria. Energy and Ancillary Services Offset. DCWG

#4”. June 14, 2018. Slide 11.



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used to pay down debt (such as 100% or 50%), and the target level of debt paydown (i.e., the cash

flow sweep is no longer effective once a certain amount of debt has been paid down).”8

A constant capital structure over time would not be a realistic assumption for a physical asset

with a limited economic life. To test these assumptions, LEI’s pro forma financial model also

considers cash sweeps.

3.3 LEI’s pro forma model demonstrates Brattle’s ATWACC is unrealistic

LEI’s pro forma financial model relies on Brattle’s capital and debt costs assumptions, associated

Gross CONE and Net CONE values (based on AESO’s energy revenue assumptions). In addition,

LEI’s financial model reflects realistic debt provisions such as an appropriate DSCR and cash

sweep when determining the debt size and modeling the project’s cash flow.

The finance textbook “Corporate and Project Finance Modeling” describes four different methods

for sculpting debt: 9

1. using a solver tool to find both the repayments and the debt size by matching the target DSCR wit the modeled DSCR and setting the closing debt balance to zero;

2. using the definition of DSCR to determine the repayment and then sets the ending debt balance to zero by changing the debt size using the Goal Seek tool;

3. uses the fact that net present value of debt service is equal to the remaining debt balance to establish the size of the debt; and ,

4. backward induction approach that begins with a zero balance at the end of the debt term, and work backwards to establish the amount of the debt at commercial operation.

The method LEI uses in the pro forma model is the third method. The logic of LEI’s pro forma

model is presented in Figure 3.

8 Standard & Poor’s. “Standard & Poor’s Project Finance Ratings Criteria – Reference Guide”. September 16, 2014.

Page 85.

9 Edward Bodme. “Corporate and Project Finance Modeling.” October 2014. Chapter 41.



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Figure 3. Illustration of merchant peaker pro forma model logic

It should be noted that the purpose of the model is not to suggest the correct assumed leverage

or specific DSCR or cash sweep values for a merchant peaking plant in Alberta. Instead, the pro

forma model is intended to numerically illustrate the internal inconsistency between Brattle’s

ATWACC and realistic financing requirements that would affect returns for investors. The

financial modeling analysis show that once certain reasonable debt structure requirements are

added to the financial analysis, the expected return to equity would be unattractively low for

investors. LEI recommends that AESO request that Brattle consider such real-world financing

considerations in its final Gross CONE calculations.

3.3.1 Assumptions

Using Gross CONE assumptions developed by Brattle and AESO’s energy & AS offset value to

yield a preliminary Net CONE, LEI created a 20-year pro forma financial. The key assumptions10

include:

▪ the reference technology is an Aero-Type combustion Turbine with capital costs at Cdn. $1,533/kW, consistent with Brattle’s presentation on June 14, 2018

10 The capital cost, ATWACC, resulting Gross CONE, and fixed O&M expenses, are all based on Brattle’s

assumptions presented to AESO’s Technical Working Group Session #4 on June 14, 2018, while the energy

profits are based on AESO’s presentation for Technical Working Group Meeting #3 on May 4, 2018. (Note, the

energy profits are an implied value, based on a Gross CONE of Cdn. $224.9/kW-year and the Net CONE in

2021 of Cdn. $45.19/kW-year presented by AESO using preliminary estimates off of forward prices).

AESO’s upfront capital cost

Brattle’s ATWACC

Gross CONEAnnual capacity + energy profit

AESO’s fixed O&M costs

EBITDADSCR

requirement

Maximum serviceable loan

Brattle’s cost of debt

Loan tenure

Annual interest payment

Annual principal

repaymentAnnual

Depreciation

EBIT Tax rateCash flow to equity holder

Realized ROE

Minimum upfront equity

Cash sweep percentage

AESO/Brattle assumption

LEI assumption based on common debt terms

Implied/calculated number

Color code



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▪ the cost of debt is assumed to be 6%, based on Brattle’s low-end estimate consistent with Brattle’s presentation on June 14, 2018;

▪ debt term of 20 years based on Brattle assumption in presentation on June 14, 2018; ▪ tax rate of 27%, same as Brattle’s assumption from presentation on June 14, 2018; ▪ the generator would be able to earn exactly the forecasted energy profits in the energy

market every year that correspond to AESO’s estimate of E&AS, which are captured in a Net CONE;

▪ the generator would be able to earn a capacity price exactly equal to this same Net CONE in the capacity market every year; and

▪ the generator would incur exactly the same amount of expected fixed O&M costs over its lifetime as was estimated in the Gross CONE.

The amount of debt is based on the DSCR threshold of 2.5x instead of an assumed level of

leverage. In addition, LEI considered the requirement for cash sweeps. The model’s primary

output is a calculated return on equity, which is then compared to the returns that Brattle

identified in its ATWACC analysis.

A truncated snapshot of the financial pro forma showing the results for 2021-2026 is presented in

Figure 4 below. The full 20-year (2021-2040) model is available in the appendix. With a DSCR

requirement of 2.5x, the project would be able to obtain an initial 50% debt-to-capital ratio.

However, the realized return on equity (shown as internal rate of return (“IRR”) value), is only

9.23%, which is lower than the cost of equity range of 11.6% to 13.4% assumed by Brattle in its

ATWACC calculation.



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Figure 4. Project proforma with debt sized using 2.5x DSCR (2021-2026) (Cdn.$)

Source: LEI analysis

Note that in the model, the DSCR is fixed over the modeling period because the net operating

income does not change. Therefore, the DSCR’s limiting constraint on debt size is fixed, and

refinancing is not a realistic option to the project unless a new financier is willing to take on a

higher level of risk than the original lender, or the expected revenue of the project increases. As

debt principal is being paid down over time, the return on equity realized by the project would

Peaker 2021 2022 2023 2024 2025 2026

Financing

Upfront Capital cost ($/kW) 1,533.00$

Debt ($/kW) 50% $767.57

Equity ($/kW) 50% $765.43

Cost of debt (%) 6.00%

IRR on equity (%) 9.23%

Tax rate 27%

Assumed ATWACC 8.00%

Assumed debt term 20

Cash sweep 0%

Target DSCR 2.5

Interest expense ($/kW) $46.05 $44.80 $43.47 $42.07 $40.58 $39.00

Base principal repayment ($/kW) $20.87 $22.12 $23.45 $24.85 $26.34 $27.92

Cash Sweep Principal payment ($/kW) $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

Remaining principal ($/kW) $767.57 $746.70 $724.58 $701.14 $676.29 $649.94 $622.02

Implied debt term 20.00

Debt service amount $66.92 $66.92 $66.92 $66.92 $66.92 $66.92

Average life-time leverage 28.5%

Cash flow

Capacity market revenue ($/kW) 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$

Energy market profit ($/kW) 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$

Fixed O&M 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$

EBITDA ($/kW) 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$

DSCR 2.50 2.50 2.50 2.50 2.50 2.50

Maximum annual debt service amount ($/kW) 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$

Interest payment ($/kW) 46.05$ 44.80$ 43.47$ 42.07$ 40.58$ 39.00$

Depreciation ($/kW) 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$

EBIT ($/kW) 44.60$ 45.85$ 47.18$ 48.58$ 50.07$ 51.65$

Tax 12.04$ 12.38$ 12.74$ 13.12$ 13.52$ 13.95$

FCFE (765.43)$ 88.34$ 88.00$ 87.64$ 87.26$ 86.86$ 86.43$

GROSS CONE implied from Assumed ATWACC 224.9 224.9 224.9 224.9 224.9 224.9

Assumed eneryg profits 179.7 179.7 179.7 179.7 179.7 179.7

Net CONE 45.2 45.2 45.2 45.2 45.2 45.2

Clearing price (multiple of Net CONE) 1 45.2 45.2 45.2 45.2 45.2 45.2

Legend

Brattle's Assumption

LEI Assumption

Key model Outputs



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be lower than the assumed cost of equity in Brattle’s ATWACC, as not all available cash is payable

to the equity owner.

This means that Brattle’s ATWACC and Gross CONE methodology is internally inconsistent. By

taking into account a realistic and fundamental aspect of the financing - the DSCR - the capital

structure will result in a situation where an equity investor will not be able to achieve the return

on equity assumed within the ATWACC that Brattle developed to get to the Gross CONE value.

In other words, a capacity demand curve derived from the ATWACC proposed by Brattle will

not result in an attractive return to investors – the realized return to equity for investors would

actually be lower than the risk-adjusted return that Brattle uses to estimate its ATWACC.

3.3.2 Adding in cash sweep provisions

In addition, it is possible that the financing institution would want to add a cash sweep provision

in the debt structure for a new generation project. Such provisions have become common in a

merchant power environment, in order to protect lenders against volatile and sometimes

prolonger uneconomic market conditions. Lenders use cash sweeps to guard against a risk that

the asset may be functionally obsolete before all the debt is paid down (or refinanced). As such,

cash sweeps are a way for lenders to mandate loan repayment over a shorter timeframe than the

nominal term of the load. For example, if the financing institution expects the total bankable life

of the merchant peaker to be 15 years11 - with the initial loan term being 10 years and a re-

financing contemplated for an additional five years, then it is possible that the bank would ask

for a cash sweep would be 70% - such that the initial loan is expected to be fully repaid around

year 10.

A truncated model showing the proforma with a 70% cash sweep, but at a lower DSCR of 1.8x

requirement (to offset the cash sweep provision, which lowers the riskiness of the loan, and also

reflecting the low end of DSCR requirement for investment grade bond based on Fitch Ratings’

guidance presented earlier in the paper), for 2021-2026 is presented in the figure below. The full

20-year (2021-2040) model is available in the appendix. In this scenario, due to the lower DSCR,

the project would be able to increase its leverage to 70%. However, without refinancing after the

first loan is paid down, the return on equity is only 8.86%, which again shows that a merchant

peaker in Alberta would be an unattractive investment as compared to the 11.6% to 13.4% return

on equity required by investors in Brattle’s ATWACC.

11 For reference in the US, the modified accelerated cost recovery system (“MACRS”) schedule of a combustion

turbine is 15 years



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Figure 5. Pro forma model with 70% cash sweep and 1.8x DSCR (2021-2026) (Cdn.$)


As an additional verification of the conclusions, LEI also tested what would happen if the project

were to obtain refinancing in year 11 with a 5-year loan, and the size of the loan were based on a

1.8x DSCR for the subsequent five years. This scenario resulted in a return on equity of 9.12%,

which is an improvement over no-refinancing, but still lower than Brattle’s assumed return on

Peaker 2021 2022 2023 2024 2025 2026

Financing


Debt ($/kW) 70% $1,066.07

Equity ($/kW) 30% $466.93



Tax rate 27%



Cash sweep 70%

Target DSCR 1.8




Remaining principal ($/kW) $1,066.07 $990.08 $910.40 $826.84 $739.21 $647.32 $550.96




Cash flow



Fixed O&M 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$

EBITDA ($/kW) 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$

DSCR 1.80 1.80 1.80 1.80 1.80 1.80



Depreciation ($/kW) 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$

EBIT ($/kW) 26.69$ 31.25$ 36.03$ 41.04$ 46.30$ 51.81$

Tax 7.21$ 8.44$ 9.73$ 11.08$ 12.50$ 13.99$

FCFE (466.93)$ 20.15$ 19.78$ 19.39$ 18.98$ 18.56$ 18.11$



Net CONE 45.2 45.2 45.2 45.2 45.2 45.2

Clearing price (multiple of Net CONE) 1 45.2 45.2 45.2 45.2 45.2 45.2

Legend


LEI Assumption

Key model Outputs



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equity in its recommended ATWACC. The detailed model for this additional verification scenario

is available in the appendix.

key finding from the pro forma modeling exercise is that the return on equity realized by a

merchant peaking plant would be less than the assumed cost of equity in Brattle’s ATWACC, and

the reason for this is because Brattle has not considered the realistic debt requirements that will

drive the financing of such merchant generation projects. Therefore, Brattle’s estimated

ATWACC of 8% is too low. As a consequence, the resulting Net CONE will not attract private

investment. This conclusion is not conditioned on the specific DSCR multiple and cash sweep

percentage. Indeed, as shown in Figure 6, the realized return on equity will be below the assumed

cost of equity in Brattle’s ATWACC under a variety of SCR and cash sweep considerations.

Figure 6. Sensitivity analysis on return on equity under different debt terms (DSCR and cash sweep)

3.3.3 Less ideal market conditions scenario

The results of the financial model presented in Figure 4 and Figure 5 reflect ideal market outcomes

– the reference peaker would not readily expect to always earn capacity revenues at its Net CONE

and energy revenues consistent with that the Net CONE projection. There are many risks to

future energy and capacity markets. Therefore, the analyses and conclusions presented above are

likely an overly optimistic reflection of potential market outcomes. In order for the capacity

market to clear at Net CONE every year, it would require new generators to clear the capacity

market every year. If this is not the case, the capacity market would likely clear below Net CONE

as “new” resources that cleared in previous years would become “existing” resources and would

bid their avoidable costs, which would be well below the Net CONE.

Furthermore, in the pro forma model presented in Figure 5, at a 6% cost of debt, the level of

leverage is 70%. But according to Brattle’s analysis, at a 65% leverage, it would expect the cost of

debt to be 100 basis points higher, at 7%. This would increase the interest payments each year,

which in turn would lower the amount of debt the project could carry due to limitations from the

DSCR.

To illustrate a less idealized market revenue outlook, we created another scenario for the

proforma model. While keeping the 70% cash sweep and 1.8x DSCR, we further assumed that

after the first year, the capacity market would clear at 0.9x Net CONE instead of 1.0x Net CONE

to reflect the likelihood that new assets would not clear the capacity market every year.

Furthermore, we increased the cost of debt from 6.0% to 6.5% to reflect a higher level of leverage.

10.27% 0% 25% 50% 75% 100%

1.8 12.2% 10.3% 9.3% 8.8% 8.4%

2.0 10.8% 9.3% 8.6% 8.2% 8.0%

2.5 9.2% 8.2% 7.8% 7.6% 7.5%

3.0 8.5% 7.8% 7.5% 7.3% 7.3%

3.5 8.2% 7.5% 7.3% 7.2% 7.1%

DS

CR

(x)

Cash sweep (%)



Page 14 of 18



Boston, MA 02111 Tel: (617) 933-7221


Note that these are still very pragmatic assumptions for the Alberta capacity market, and would

not constitute a true “debt” or “low” case scenario that lenders would use to stress test the

financials and size the debt. Figure 7 presents the results of this adjusted (lower revenue and

higher debt cost) pro forma model over the 2021-2026 timeframe. The full 20-year version of this

proforma model is available in the appendix. As show below, the return on equity in this scenario

drops to 7.81%. A rational investor would not invest in a merchant peaking generator project for

this level of return on equity.

Figure 7. Pro forma model with lower capacity market revenue and higher debt cost (2021-2026) (Cdn.$)


Peaker 2021 2022 2023 2024 2025 2026

Financing


Debt ($/kW) 65% $996.44

Equity ($/kW) 35% $536.56



Tax rate 27%



Cash sweep 70%

Target DSCR 1.8




Remaining principal ($/kW) $996.44 $921.86 $845.66 $765.44 $680.99 $592.09 $498.51




Cash flow



Fixed O&M 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$

EBITDA ($/kW) 167.30$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$

DSCR 1.80 1.80 1.80 1.80 1.80 1.80



Depreciation ($/kW) 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$

EBIT ($/kW) 25.88$ 26.21$ 31.16$ 36.38$ 41.87$ 47.64$

Tax 6.99$ 7.08$ 8.41$ 9.82$ 11.30$ 12.86$

FCFE (536.56)$ 20.96$ 19.58$ 19.18$ 18.76$ 18.31$ 17.84$



Net CONE 45.2 45.2 45.2 45.2 45.2 45.2

Clearing price (multiple of Net CONE)0.9 45.2 40.7 40.7 40.7 40.7 40.7

Legend


LEI Assumption

Key model Outputs



Page 15 of 18 London Economics International LLC contact:


Boston, MA 02111 Tel: (617) 933-7221


4 Appendix

Figure 8. Project proforma using Brattle’s ATWACC and Gross CONE assumptions with debt sized using a 2.5x DSCR (Cdn.$)

Peaker 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

Financing


Debt ($/kW) 50% $767.57

Equity ($/kW) 50% $765.43



Tax rate 27%



Cash sweep 0%

Target DSCR 2.5

Interest expense ($/kW) $46.05 $44.80 $43.47 $42.07 $40.58 $39.00 $37.32 $35.55 $33.66 $31.67 $29.55 $27.31 $24.93 $22.41 $19.74 $16.91 $13.91 $10.73 $7.36 $3.79

Base principal repayment ($/kW) $20.87 $22.12 $23.45 $24.85 $26.34 $27.92 $29.60 $31.37 $33.26 $35.25 $37.37 $39.61 $41.99 $44.51 $47.18 $50.01 $53.01 $56.19 $59.56 $63.13

Cash Sweep Principal payment ($/kW) $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00

Remaining principal ($/kW) $767.57 $746.70 $724.58 $701.14 $676.29 $649.94 $622.02 $592.42 $561.05 $527.79 $492.54 $455.17 $415.56 $373.57 $329.07 $281.89 $231.88 $178.88 $122.69 $63.13 $0.00


Debt service amount $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92 $66.92


Cash flow

Capacity market revenue ($/kW) 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$ 45.20$

Energy market profit ($/kW) 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$ 179.70$

Fixed O&M 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$

EBITDA ($/kW) 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$

DSCR 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50

Maximum annual debt service amount ($/kW) 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$ 66.92$

Interest payment ($/kW) 46.05$ 44.80$ 43.47$ 42.07$ 40.58$ 39.00$ 37.32$ 35.55$ 33.66$ 31.67$ 29.55$ 27.31$ 24.93$ 22.41$ 19.74$ 16.91$ 13.91$ 10.73$ 7.36$ 3.79$

Depreciation ($/kW) 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$

EBIT ($/kW) 44.60$ 45.85$ 47.18$ 48.58$ 50.07$ 51.65$ 53.33$ 55.10$ 56.99$ 58.98$ 61.10$ 63.34$ 65.72$ 68.24$ 70.91$ 73.74$ 76.74$ 79.92$ 83.29$ 86.86$

Tax 12.04$ 12.38$ 12.74$ 13.12$ 13.52$ 13.95$ 14.40$ 14.88$ 15.39$ 15.93$ 16.50$ 17.10$ 17.74$ 18.42$ 19.14$ 19.91$ 20.72$ 21.58$ 22.49$ 23.45$

FCFE (765.43)$ 88.34$ 88.00$ 87.64$ 87.26$ 86.86$ 86.43$ 85.98$ 85.50$ 84.99$ 84.45$ 83.88$ 83.28$ 82.64$ 81.96$ 81.24$ 80.47$ 79.66$ 78.80$ 77.89$ 76.93$

GROSS CONE implied from Assumed ATWACC 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9 224.9

Assumed eneryg profits 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7 179.7

Net CONE 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2

Clearing price (multiple of Net CONE)1 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2





Boston, MA 02111 Tel: (617) 933-7221


Figure 9. Pro forma model with 70% cash sweep and debt sized using a 1.8x DSCR (Cdn.$)

Peaker 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

Financing


Debt ($/kW) 70% $1,066.07

Equity ($/kW) 30% $466.93



Tax rate 27%



Cash sweep 70%

Target DSCR 1.8




Remaining principal ($/kW) $1,066.07 $990.08 $910.40 $826.84 $739.21 $647.32 $550.96 $449.91 $343.94 $232.81 $116.28 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00




Cash flow



Fixed O&M 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$

EBITDA ($/kW) 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$

DSCR 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80


Interest payment ($/kW) 63.96$ 59.40$ 54.62$ 49.61$ 44.35$ 38.84$ 33.06$ 26.99$ 20.64$ 13.97$ 6.98$ -$ -$ -$ -$ -$ -$ -$ -$ -$

Depreciation ($/kW) 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$

EBIT ($/kW) 26.69$ 31.25$ 36.03$ 41.04$ 46.30$ 51.81$ 57.59$ 63.66$ 70.01$ 76.68$ 83.67$ 90.65$ 90.65$ 90.65$ 90.65$ 90.65$ 90.65$ 90.65$ 90.65$ 90.65$

Tax 7.21$ 8.44$ 9.73$ 11.08$ 12.50$ 13.99$ 15.55$ 17.19$ 18.90$ 20.70$ 22.59$ 24.48$ 24.48$ 24.48$ 24.48$ 24.48$ 24.48$ 24.48$ 24.48$ 24.48$

FCFE (466.93)$ 20.15$ 19.78$ 19.39$ 18.98$ 18.56$ 18.11$ 17.64$ 17.15$ 16.64$ 16.10$ 21.45$ 142.82$ 142.82$ 142.82$ 142.82$ 142.82$ 142.82$ 142.82$ 142.82$ 142.82$



Net CONE 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2






Boston, MA 02111 Tel: (617) 933-7221


Figure 10. Pro forma model with 70% cash sweep and debt sized using a 1.8x DSCR and refinancing (Cdn.$)

Peaker 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

Financing


Debt ($/kW) 70% $1,066.07

Equity ($/kW) 30% $466.93



Tax rate 27%



Cash sweep 70%

Target DSCR 1.8




New debt $391.52

Remaining principal ($/kW) $1,066.07 $990.08 $910.40 $826.84 $739.21 $647.32 $550.96 $449.91 $343.94 $232.81 $116.28 $391.52 $282.71 $168.60 $48.95 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00




Cash flow



Fixed O&M 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$

EBITDA ($/kW) 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$ 167.30$

DSCR 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80


Interest payment ($/kW) 63.96$ 59.40$ 54.62$ 49.61$ 44.35$ 38.84$ 33.06$ 26.99$ 20.64$ 13.97$ 6.98$ 23.49$ 16.96$ 10.12$ 2.94$ -$ -$ -$ -$ -$

Depreciation ($/kW) 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$

EBIT ($/kW) 26.69$ 31.25$ 36.03$ 41.04$ 46.30$ 51.81$ 57.59$ 63.66$ 70.01$ 76.68$ 83.67$ 67.16$ 73.69$ 80.53$ 87.71$ 90.65$ 90.65$ 90.65$ 90.65$ 90.65$

Tax 7.21$ 8.44$ 9.73$ 11.08$ 12.50$ 13.99$ 15.55$ 17.19$ 18.90$ 20.70$ 22.59$ 18.13$ 19.90$ 21.74$ 23.68$ 24.48$ 24.48$ 24.48$ 24.48$ 24.48$

FCFE (466.93)$ 20.15$ 19.78$ 19.39$ 18.98$ 18.56$ 18.11$ 17.64$ 17.15$ 16.64$ 16.10$ 412.97$ 16.87$ 16.34$ 15.78$ 91.73$ 142.82$ 142.82$ 142.82$ 142.82$ 142.82$

Remaining borrowing power -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 41.06$ 92.94$ 92.94$ 92.94$ 92.94$ 92.94$



Net CONE 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2






Boston, MA 02111 Tel: (617) 933-7221


Figure 11. Pro forma model with lower capacity market revenue and higher cost of debt (Cdn.$)

Peaker 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

Financing


Debt ($/kW) 65% $996.44

Equity ($/kW) 35% $536.56



Tax rate 27%



Cash sweep 70%

Target DSCR 1.8




Remaining principal ($/kW) $996.44 $921.86 $845.66 $765.44 $680.99 $592.09 $498.51 $399.99 $296.28 $187.10 $72.17 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00




Cash flow



Fixed O&M 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$ 57.60$

EBITDA ($/kW) 167.30$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$ 162.78$

DSCR 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80 1.80


Interest payment ($/kW) 64.77$ 59.92$ 54.97$ 49.75$ 44.26$ 38.49$ 32.40$ 26.00$ 19.26$ 12.16$ 4.69$ -$ -$ -$ -$ -$ -$ -$ -$ -$

Depreciation ($/kW) 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$ 76.65$

EBIT ($/kW) 25.88$ 26.21$ 31.16$ 36.38$ 41.87$ 47.64$ 53.73$ 60.13$ 66.87$ 73.97$ 81.44$ 86.13$ 86.13$ 86.13$ 86.13$ 86.13$ 86.13$ 86.13$ 86.13$ 86.13$

Tax 6.99$ 7.08$ 8.41$ 9.82$ 11.30$ 12.86$ 14.51$ 16.24$ 18.06$ 19.97$ 21.99$ 23.26$ 23.26$ 23.26$ 23.26$ 23.26$ 23.26$ 23.26$ 23.26$ 23.26$

FCFE (536.56)$ 20.96$ 19.58$ 19.18$ 18.76$ 18.31$ 17.84$ 17.35$ 16.83$ 16.29$ 15.71$ 63.94$ 139.52$ 139.52$ 139.52$ 139.52$ 139.52$ 139.52$ 139.52$ 139.52$ 139.52$



Net CONE 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2 45.2

Clearing price (multiple of Net CONE)0.9 45.2 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7 40.7



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