Guest Post by David Vardy
Former CFO Derrick Sturge told the Muskrat Falls Inquiry the project and
its financing were “rock solid”. CEO Stan Marshall told us two years ago the
project would “finish strong”.
Labradorians that they will not bear the burden of higher electricity rates or
taxes as a result of Muskrat Falls. We will deliver on that promise.”
questions from the media confirming the delays which had already become well
known. He did not provide a cost update on the project, which appears likely to
exceed the official 2017 estimate of $12.7 billion. He repeated the statement
that Nalcor would “finish strong”.
Stan Marshall’s press conference followed on the heels of the
announcement on February 10, 2020 by Premier Dwight Ball and Natural Resources
Canada Minister Seamus O’Regan of a framework for refinancing Muskrat Falls in
order to make power rates affordable.
avoid massive increases? Do the two media events signal a “strong finish” as
promised by CEO Marshall? Do they confirm that that citizens will “not bear the
burden of higher electricity rates or taxes as a result of Muskrat Falls”?
perhaps 2021 or maybe later, along with the April 2019 Rate Mitigation Plan
and cost savings in the amount of $726 million as shown in the framework document and summarized in
the table below:
This shows a high reliance both on dividends ($200 million) and on help
from the federal government ($200 million), both adding to $400 million of the
$726 million in revenue requirements.
amount, only $193 million, toward the $726 million in 2021 revenue
requirements, rather than the $529 million in the rate mitigation plan of April
2019. Clearly the PUB took a more conservative and realistic view of the
options. There is a big disconnect between the April 2019 rate mitigation plan
and the February 2020 report of the PUB.
below, the $726 million is a low estimate of the 2021 costs, known as “revenue
requirements”. It is lower than the $808
million estimate used by Nalcor in 2017 and the official cost estimate of $12.7
billion has not changed. The $12.7 billion is an understatement of the capital
cost of the project, as explained in the technical appendix, and should be
closer to $13.8 billion. The costs imposed on both ratepayers and taxpayers to
supply the projected energy requirements of 2021 are more than $1 billion, much
higher than the 2021 revenue requirements used both by the PUB and by
government. This is explained in the Technical Appendix below.
for 2021 and close to half of that amount is forgiveness of dividends, which
were fictitious from the start. By 2030, 72% of the mitigation potential is
forgiveness of non-existent dividends. It will be difficult to keep power rates
at 13.5 cents/KWh in 2021 and to hold them at that level in subsequent years.
diverts revenues from other purposes. The additional revenues from exports and
from electrification will be modest in the early years. The magnitude of the
shortfall is such that a major infusion will be required from the federal
government. The federal government may offer some relief on sinking funds and
on pre-payment of cost overruns but that simply shifts the problem into the
future. Similarly an increase in the federal loan guarantee might be used to
offer some relief to the province but ultimately the burden will fall on
ratepayers or taxpayers in the province.
|David Vardy (Photo Credit : The Telegram)|
What can the federal government do to assist the province? They could inject new equity into the project
in order to bear more of the project’s risk and to recognize that the benefits
of the project, if any, will flow to other Canadians, particularly Nova
Scotians. Additionally, the federal government could enhance its equalization
program or other support programs. They could enhance fiscal stabilization
payments or increase payments under Canada
Health Transfers (CHT), and under Canada Social Transfers (CST). The burden of
Muskrat Falls is best addressed through the prism of fiscal policy in
recognition of the fact that the fiscal impact far outweighs any energy
rate mitigation focused on opportunities to raise revenue through the sale of additional
electric power and by making the provincial power system more efficient. The
opportunities to raise revenues through increased electrification will take
time to achieve and will be modest in scale. Without major restructuring of our
electric power industry the opportunities for cost savings are equally modest.
The province can divert revenues, such as offshore royalty revenues and
revenues from equity investment in oil and gas, but this will simply take money
away from other social priorities and from debt reduction.
dividends from the Labrador Island Link is relatively modest. If these were
somehow capitalized they would generate little revenues. If they were monetized
at the front end it would simply shift the problem into the future. But what is
“monetization”? It is a euphemism for borrowing against future revenues, which
is no cure. It simply allows the problem to grow exponentially and to shift a
growing burden to future generations.
3. Deferral of sinking fund payments until the end of 2021 and a waiver of
pre-funding of cost overruns.
sinking fund requirements provides some immediate cash relief as does the
waiver of the need to pre-fund cost overruns. This tinkering does not reflect
the magnitude of the problem.
contract and which places 100% of the cost on ratepayers on the Island.
agreement between Muskrat Falls Power Corporation (Nalcor) and NL Hydro. It
places the obligation to pay on Hydro. Hydro must in turn place 100% of the
cost on power consumers, on industrial customers and on the customers of
Newfoundland Power and NL Hydro. This 50 year contract locks ratepayers into a
death spiral, where high rates force ratepayers to cut back and Hydro responds
by raising rates even higher. Already the demand for power has ratcheted down
in anticipation of higher power rates.
of the PPA is absolutely necessary. Ratepayers who will consume little if any
Muskrat Falls power cannot be expected to absorb 100% of the costs, any more
than customers in the Maritimes or New England can be expected to cover the
costs of Muskrat Falls. The PPA is at the heart of a flawed business plan,
which depended upon legislation to create Nalcor as an unregulated monopoly.
This locks our electric power industry, along with the rest of the provincial
economy, into a high cost electricity system and prevents the adoption of new,
low cost technology.
that “At the core
of our agreement is the requirement to transition the Muskrat Falls/Labrador
Transmission Assets revenue model to a Cost of Service model, which will ensure
that equity returns are redirected from Nalcor to ratepayers.”
are recovered through power rates, using a combination of “cost of service”
(COS) and “escalating supply prices”
(ESP). COS ensures that rates cover all costs on an annual basis and this is
the traditional model used by the PUB in NL and by many other jurisdictions.
The ESP model tends to shift some of these costs into the future, particularly
the return on provincial equity. All costs are recovered over a 50 year “supply
period”. A description of these models is found in the Technical Appendix.
full COS model and the rejection of the hybrid approach “at the core” of their refinancing
agreement. The hybrid approach leads to rising costs, or revenue requirements.
Using the latest numbers from Nalcor they rise from $726 million in 2021 to
$920 million in 2030 and to $2.5 billion in 2069. A COS model would lead to
higher revenue requirements at the beginning but they would taper off over
time. The Ball-O’Regan announcement writes off $30 billion in dividends (ROE)
on generation assets, a write-down from about $39 billion in dividends over the
50 year supply period. Whether the
federal government will inject new funds remains unknown but such an injection
is necessary. Without access to the spreadsheets underlying the public
announcement it is difficult to say.
approach alone will not bring power rates down to 13.5 cents/KWh. Nor will it
keep them there. What appears to be under discussion is a modified cost of
service approach plus a write-down of provincial equity. A write down of equity
can produce impairment on the province’s public accounts and an increase in our
net debt (see Technical Appendix).
need for more accountability and transparency as the province moves into
negotiations with the federal government. We need to understand that we are not
just shifting the burden down to future generations. The hybrid approach was
intended to avoid “rate shock” by just such shifting of financial burden. If we
as a generation are to act responsibly to our children and grandchildren we
need to avoid adding an increasing load of debt.
is needed to stabilize power rates and to create a sustainable electric power
system. Muskrat Falls was intended to be a solution to a perceived energy
problem. It has instead exacerbated a growing fiscal crisis and has to be
treated with the instruments of fiscal policy, bringing to bear federal support
programs designed to mitigate not only power rates but the other fiscal
pressures upon us. Realistically such support can only come as part of an
agreement which imposes fiscal discipline on the province, as would be the case
if we were a fiscally beleaguered nation seeking succor from the World Bank or
the International Monetary Fund. We cannot expect other Canadians to share the
burden unless we show we are ready to make sacrifices.
“rock solid” as described by the former Nalcor CFO. They know that a “strong
finish” is wishful thinking, rooted in delusion. Citizens are not gullible.
They cannot accept the promise they will be saved “from the burden of higher
electricity rates or taxes as a result of Muskrat Falls.” They are willing to
bear their share of the burden along with other Canadians.
the numbers are estimates for a project yet to be completed and whose schedule
and costs remain highly uncertain.
concepts and measures that are used in the public dialogue on Muskrat Falls. My
hope is that it will unravel some of the complexity and also create some
understanding as to how high the stakes are in these negotiations. In the
appendix I show how both the capital costs of Muskrat Falls and the size of our
provincial equity investment are underestimated. The technical appendix also
explains how “economies of scale” impact on the project and how such a large
project, whose scale far exceeds the power needs of the province, makes it an
inappropriate fit for the province. I conclude with a discussion of net debt.
transmission assets. COS requires that costs be recovered from ratepayers each
year. The capital costs are primarily the cost of interest on debt, the cost of
debt repayment, the cost of equity capital raised from shareholders and the
return of equity to shareholders. Depreciation is a surrogate for the repayment
of bond and equity investment. To this must be added the cost of operations and
maintenance, fuel costs, water power rentals and payments to the Innu Nation.
billion in direct costs plus $2.6 billion in financing costs, for a total of
$12.7 billion. This official estimate has not yet been revised. The annual
revenue requirements on which power rates are based were estimated in 2017 at
$808 million for 2021, the first year of full power. In 2019 this estimate was
revised downward to $726 million and it is this estimate which has been used
both by the PUB and by government as the incremental cost of Muskrat Falls.
savings if power rates are to be stabilized. It is difficult to accept the
notion that revenue requirements can realistically be expected to be lower than
those estimated in 2017 in light of known cost escalation which has
materialized since that time, including the problems with synchronous
condensers and the costs arising from GE’s inability to produce transmission
software on schedule. For this reason I am disinclined to accept an estimate
lower than the $808 million for 2021 revenue requirements.
of service” and “escalating supply prices (ESP)” or “PPA rates” (based on a power
purchase agreement). The pattern of revenue requirements for the cost of
service model is generally one which declines over time while the ESP or PPA
model shifts certain costs into the future and leads to revenue requirements
which rise over time. Since generation costs for this project are higher than
transmission costs the ESP model applied to generation assets dominates the
revenue requirements and produces rising costs, growing from $808 million
(using 2017 estimates) to $2.5 billion in 2069. This is referred to as “back
end loading”. This is in contrast to the tendency under COS cost recovery for “front
end loading” of costs.
costs today and to shift them into the future. Expenses are capitalized so they
are not expensed or recovered in the year in which the costs are incurred. Such
shifting mechanisms have led to controversy in British Columbia and Ontario in
particular. In the case of Muskrat Falls the shifting of costs was intended to
avoid rate shock through the adoption of an unorthodox ESP approach. This
hybrid model has been in place since the PUB reference of 2011, if not before.
investment in generation assets, currently $4.2 billion. The return on equity
of 8.4% is built into the costs and recovered over a 50 year “supply period”
and is “back end loaded” with most equity returns in later years, 2041 and
beyond. The $726 million in 2021revenue requirements used by the province and
by the PUB provides $57 million in return on the province’s $645 million in
provincial equity but no return on equity for the province’s $4.2 billion in
ostensibly on an interim basis until such time as rising demand and rising
nominal revenues allow repayment to be made to the shareholder. Using 8.4% as
the cost of equity capital and applying this to the $4.2 billion in equity invested
by the province results in an additional cost of $353 million, which needs to
be added to the $726 million in revenue requirements targeted in the province’s
rate mitigation plan of April 2019. If we instead use 3% as the cost of
borrowing this additional cost becomes $126 million. To this we add $210
million to repay borrowed funds over 50 years we get $336 million. It is
difficult to see how the cost to ratepayers and taxpayers in 2021 would be less
than $1 billion, much higher than the $726 million target.
8.4% return and to return the original equity investment to the province. This
is hardly credible. At the outset it was highly questionable whether the dividends
would materialize. With more realistic demand projections, based on realistic
assumptions on population growth and demand elasticity, along with doubling of capital
costs, the prospect of dividends is remote.
of February 10, 2020 are an admission that the business plan for the project is
fatally flawed and that dividends are fictitious. The Ball-O’Regan Accord
recognizes that $30 billion in dividends over the 50 year supply period is not
realistic and must be written off.
project, both those paid by ratepayers and those transferred to taxpayers. For
this reason it is necessary to reflect the full financing arrangements and to
include the full cost of the project, including the cost of financing the funds
borrowed by the province to invest equity into the project.
capital costs are estimated at $10.1 billion dollars, with $3.7 billion for the
Labrador Island Link (LIL), $5.5 billion for the generation site (MF) and $0.9
billion for the transmission line between Churchill Falls and Muskrat Falls,
known as Labrador Transmission Assets (LTA). The generation site (MF) and
Labrador Transmission Assets (LTA) are referred to as “generation assets” and
their direct capital cost together are estimated at $6.4 billion, representing
63.3%, vs 36.7% for the Labrador Island
the official cost estimate of $12.7 billion. These financing costs are the
subject of sections 2.3-2.6 of the Oversight Committee report for the period
ending September 2017 and dated November 3, 2017. Section 2.6 reports that for
the LIL the allowance for funds used during construction (AFUDC) is estimated
at $440 million, which is included in the financing costs. No such estimate is
included for AFUDC on the generation assets, which means that the estimate
assumes zero opportunity cost for $6.4 billion in direct capital costs. To
estimate how much should be added to correct this omission I have taken the LIL
AFUDC of $440 million as a proxy and made two adjustments. The first reflects the fact that generation
assets are 72% higher in direct capital costs ($6,404million/$3,714 million) than the costs of
the LIL. The second reflects the fact that the minimum equity in generation
costs, as required in the 2012 federal loan guarantee, is 35%, vs 25% in the
LIL or 40% higher (35%/25%). Accordingly I have taken the $440 million in LIL AFUDC and multiplied
it by 2.41 (1.72 x 1.4), providing my estimate of AFUDC on generation assets of
$1,060 million. Adding this AFUDC for generation assets to the official cost
estimate of $12.7 billion produces an adjusted cost estimate of $13.8 billion.
generation equity, disclosed in PB-519-2019 Table 4, is $3.1 billion. To this
must be added the AFUDC of $1.1 billion ($1,060 million rounded) to produce an
estimate of provincial equity investment, at the time of project commissioning,
of $4.2 billion. To this must be added the $645 million in LIL equity invested
by the province to produce an estimate of total provincial equity investment of
model for cost recovery of the capital costs of Muskrat Falls is based on the
concept that the real unit cost per kilowatt hour will remain constant over the
50 year supply period. Costs are
levelized over the 50 year period and then increased by 2% annually to reflect
inflation. This inflation rate is
applied to the Levelized Unit Energy Cost (LUEC). Cost recovery depends upon
escalating demand for power at a rate which is held constant in real terms. If
demand does not escalate then the revenues produced will fail to cover costs,
let alone generate dividends on provincial equity.
secured by mortgages held by the federal government on the assets financed. The
power purchase agreement also forms part of the collateral. Provincial equity
on the other hand, is not secured. It is fully at risk. Dividends can only be
paid if there is a return on equity left after all other costs have been
covered. Dividends are not guaranteed. Building an allowed rate of return of
8.4% into the model does not provide an assurance that the shareholder, GNL,
will be compensated for the cost of the borrowed funds used to finance the
equity, let alone dividends on top of that. Shareholders take the risk that dividends may
fall short of expectations and may turn into losses.
of scale and can achieve its full potential at lowest cost when demand rises
sufficiently to absorb the full 4.641 TWh of net energy produced after line
losses are deducted from the plant’s rated output of 4.9 TWh. Stan Marshall’s
presentation of February 15, 2018 at Memorial University, entitled
“Understanding Muskrat,” showed us a unit cost of 17.42 cents/KWh, assuming the
full output could be sold at cost-compensatory rates. The presentation shows only
1,324 GWh out of 4641 GWh projected to
be used on the Island in 2021, costing 61 cents/KWh, based on 2021 revenue
requirements of $808 million. If we add back the return on equity of $353
million and revise the revenue requirement up to $1,163 million then the cost
per KWh becomes 88 cents/KWh. Unit costs are high when demand is low.
the economies of scale from Muskrat Falls in his following chart 7:
which dip for a period and then rise, exceeding the unit costs of the
interconnected Island option shown in red up to the crossover point, beyond
which they rise and then remain stable in real terms. The unit costs of the
Interconnected Island system decline and then stabilize for the rest of the
period. This is consistent with the information from Stan Marshall’s
presentation. It depends upon the growth in demand which had been projected by
Nalcor. If demand does not materialize unit costs will remain high and
dividends will be elusive.
future demand. As we have shown previously the cost overruns pose a threat to
dividends early in the planning period and will also impact on future
dividends. Despite the long 50 year planning horizon or “supply period”, going
well beyond the end of the Churchill Falls contract in 2041, there is a very
high risk that the shareholder will experience negative returns. This in turn
will create pressure for a write-down of the equity investment in the project.
General defined net debt as follows. “Net Debt represents all the liabilities of the Province less
its financial assets and indicates whether there are enough financial assets to
cover the liabilities for future generations. Net Debt is a commonly used
indicator to measure the financial health of the Province.”
defines financial assets as “amounts that the Province has available to pay its
liabilities or finance future operations. Financial assets consist of cash and
temporary investments, amounts receivable from third parties, investments,
inventories held for resale and equity in Government Business Enterprises
(GBEs)…” Nalcor Energy is such a GBE and the government’s equity in Muskrat
Falls appears as a financial asset, valued at cost.
year the value of the financial assets must be assessed to determine whether a
write down is required. Currently the equity investment in Muskrat Falls is
used to offset the debt incurred by government to make the equity investment.
If the financial assets are written off completely then this could potentially
add $5 billion or more to the net debt of the province. Such an increase in our
net debt could have a detrimental impact on our fiscal ratings and may impact
on our borrowing cost and on our access to financial markets to finance our
operating deficits, our capital account spending and our refinancing of