Guest Post by PlanetNL
PlanetNL36: A Market Value Estimate of the Muskrat
Falls Project
Simple Calculations Reveal Hard Truths
Have you wondered what the $13.1B Muskrat Falls project would
be worth if it were treated as a business that had to fairly compete on the
wholesale energy market? Was it even worth
the original cost estimate of $7.4B indicated by Nalcor at the time of sanction?
This post uses a simple economic analysis method useful for determining
the fair market value of most any business or to determine if a project concept
may be viable. The accuracy of the
method mainly relies on inputting honest numbers.
This is the analysis Nalcor would not do and still refuses to acknowledge. You will see why.
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| Newfoundland and Labrador Premier Danny Williams and N.S. Premier Darrell Dexter announced terms of a deal to develop Muskrat Falls project, November 18, 2010 |
Step 1 – Establish the Fair Price of the Product
Electrical energy is a widely traded commodity of known
worth. There is plenty of market data
from other jurisdictions and within Nalcor itself that the typical wholesale price
of electricity is 4 cents/KWh.
Nalcor Energy Marketing has been getting about that price for
surplus Churchill Falls power for the past several years. It is that same market price Emera will pay
to Nalcor (under the Energy Access Agreement) for energy over and above the 1.0
TWh block of zero-cost energy they were granted in exchange for their
constructing the $1.58B Maritime Link.
The chart below is published by ISO-NE, the organization
governing the New England electricity market.
The chart shows that from 2008 to 2019, market prices have been trending
lower. Advancements in the shale gas
industry pushed wholesale electricity prices permanently downward after 2008 to
about $40/MWh USD (which is the same as 4 c/KWh; at that time the Canadian
dollar was at par). Since 2016, the
price is closer to 3 c/KWh USD (4 c/KWh CDN) as wind power has come to dominate
the market and set the price. Further
reduction in average price is probable as more wind and solar capacity enter US
markets: NE-ISO capacity auctions out to 2025 (not shown) have declined to
record lows, providing evidence that over the next few years, the market price
of energy is more than likely to decrease as well.
Source: https://www.iso-ne.com/about/key-stats/markets/
Below is data included in the 2020 Nalcor Virtual Annual
Meeting slideshow on June 10. It appears
Nalcor Energy Marketing is consistently underachieving on getting the market
price. In another slide (not shown) for
Q1/2021, they are indicating 4.1 c/KWh was achieved.
The 4 c/KWh assumption is reasonable but there is evidence of
downside risk.
Source: https://nalcorenergy.com/wp-content/uploads/2021/06/2021-AGM-Presentation_FINAL.pdf
Step 2 – Determine Gross Profit Margin Available
to Pay Back Capital Costs
The Muskrat project is estimated to have 4.6 TWh of maximum energy
available from the Soldiers Pond terminal station. At 4 c/KWh, the potential annual market revenue
would be $184M. However, as Muskrat is handicapped by the
35-year agreement to supply Emera with 1.0 TWh of energy at zero charge, the expected
revenue in this exercise is $144M.
All direct cost of goods sold must then be deducted from the
revenue. The big charge here is
operations and maintenance, presently estimated by Nalcor to be about
$80M. Muskrat is also encumbered by
provincial waterpower royalties estimated at $16M and Innu Benefit payments of
$6M until 2050, a commitment that escalates to about $60M after 30 years. As the higher Innu benefits kick in at about
the same time as the free energy period to Emera is set to expire, the two can
be considered to offset each other. Subtracting
the subtotal of $102M in operating expenses yields net annual cash flow of $42M.
There are three major risks that could seriously impact the net
cash flow projection. First is wholesale
market price erosion as covered in the previous section. Another is higher O&M costs as Nalcor
once estimated that cost to be over 30% higher – confidence in the current
estimate may be shaky. The last is
system reliability as even minor repairs on such a costly large-scale project, could
cost tens of millions while serious events would wipe out many years of net
cash flow. Besides the cost of unanticipated
repairs, failure to deliver energy during outages would also impact sales revenue.
Step 3 – Establish the Required Rate of Return and
Depreciation Rate
Rate of return includes consideration of debt, equity and risk
all rolled into one number. In 2012,
during the Muskrat review at the Public Utilities Board, Nalcor planned for 8%
return and that figure will be used in this analysis.
Crown corporations put little value on risk as they can always
turn to their government shareholder to provide more cash when troubles arise. The Federal Loan Guarantee lowered the debt
cost and the current overall rate of return target at the utility is well below
6% as bond rates have fallen in recent years.
By comparison, private businesses demand higher return levels
to compensate for risk. Suncor targets
9% in its offshore holdings and Equinor, in recently discussing the Bay du Nord
project, stated it will only pursue projects capable of at least 20% return.
While 8% is a bit high for utilities these days, Muskrat’s
risk profile warrants at least that bit extra.
Depreciation is the gradual loss of asset value and is
accounted for as a current cost. It
allows the equivalent of a rental cost to be added to operations cost. Nalcor is using the 50-year term typical for
hydro projects resulting in an annual depreciation charge of 2% of total
capital cost.
The combined 8% rate of return with 2% depreciation is 10%.
Step 4 – A Basic Math Calculation
Below is a very simple finance formula found at the core of many
economic assessments. Far more
sophisticated cash flow and valuation models can be developed but this simple
formula will be very close to the most elaborate models:
Capital Asset Value = Gross Annual
Profit divided by Rate of Return with Depreciation
Based on the estimated $42M gross annual profit, divided by 10%,
the market-based Muskrat Falls project Capital Asset Value is estimated to be $420M. That is barely 3% of Muskrat’s projected
final capital cost.
Before settling on that number, however, consider again the key
assumptions for high operating reliability, no downtime, zero unforeseen major
repairs, and zero error on O&M costs.
Only if the project performs flawlessly on all counts for 50 years is $420M
valid.
Based on the project’s track record to date, especially in the
Labrador Island Link (LIL) transmission line upon which so much depends, this
is implausible. To date the DC
convertors, synchronous condensers, control systems and software, a substantial
subsea grounding location, and extensive spans of towers and conductors have
all experienced major difficulties. The
generating plant seems quite a bit better, but it remains early days – the
stability of the quick clays known to exist within the North Spur should not be
forgotten though.
Few of those issues are realistically going away soon and for
good. 50 years of trouble-free service
is highly unlikely. The risk of costly troubles wiping out net earnings is
high.
Real Economics Paints a Devastating Picture of
Muskrat Falls
The simple formula presented above can be used to demonstrate
the magnitude of Muskrat folly in other ways.
It is routinely at the core of pre-construction viability estimates.
For example, you want to know how much annual revenue is
needed to sustainably cover the probable $13.1B capital cost? Just multiply it by 10% and add the $102M in
operating costs. The answer is $1.4B, 10
times the expected revenue.
What must the price of energy be forced up to for $1.4B? Dividing that by the 3.6 TWh of saleable
energy yields an average price of 39 c/KWh, 10 times what the wholesale market
is paying today. It is also 10 times
that of the four consecutive years prior to project sanction. Clearly, whichever way you run the numbers;
the project was not viable using fair-market prices.
That high average unit price of 39 c/KWh is misleadingly low
where ratepayers are concerned as they only need about 1.2 TWh of energy at
most. 2.4 TWh of revenue-generating
energy will be exported at prevailing market prices of around 4c/KWh yielding just
under $100M in revenue. This leaves NL Hydro
to pay the balance due of $1.3B, or about $1.10/KWh to bring the project to
break even and satisfy all capital return requirements. That is about 6 times the cost of operating Holyrood,
the plant Nalcor deemed too costly to sustain.
For Nalcor’s $7.4B sanction estimate in late 2012, the required
revenue calculation is $840M. The
average wholesale price for breakeven must be 23 c/KWh. The cost allocated to NL Hydro computes to an
energy price around 50 c/KWh, triple the cost of Holyrood. A finding of complete non-viability was a
certainty. If only this type of straightforward
analysis had been employed at the time.
Even when considering the benefit of the Federal Loan
Guarantee decreasing borrowing costs and if the required rate of return were 2%
lower, the most any of these numbers improve by is 25%. That benefit is easily offset by the risk of
realized market energy prices decreasing to 3 c/KWh which happens to be what
Nalcor has already been averaging in the last 5 years. Carbon credits, excluded from discussion for
simplicity, likewise barely move the needle (and are actually irrelevant as
they would have been earned equally by any solution that would have eliminated
the Holyrood plant).
The Backup Power Problem
All analysis above excludes the important issue that the
Island, even if Muskrat were to prove itself quite reliable, still needs a
backup power plant on the Avalon. While
Nalcor originally denied this scenario, we now know that NL Hydro has gone
before the PUB stating that serious reliability risk exists without a backup
power plant.
The top solutions are to recondition and continue operation of
the Holyrood plant with reduced fuel expenses or outright replace it with
standby combustion turbines. Either is likely
to demand anywhere from $60-100M additional required revenue. This must be regarded as a missed project
cost: Muskrat as a business unit needs the backup plant to compensate for its
inherent deficiency and the backup plant is not a cash generating business unit
itself.
The tenuous forecast of $42M in net cash flow is directly
impacted when this directly related cost is added in. Substantial net losses on operations from the
project are assured.
The Ultimate Boondoggle
On the balance of probabilities, competent project finance
professionals would have found in 2012 and would again find in 2021 that
consistent positive cashflows coming from the Muskrat Falls project were unlikely. They could only logically estimate the appropriate
capital asset value as zero.
Despite having built it, given the serious risk of recurring
operating losses and of high loss events, professional advice would likely also
recommend against putting the project into operation to avoid further financial
loss.
Even at the seeming end of the project, and even if the entire
capital cost is considered a sunk cost, a careful analysis of better
alternatives ought to be considered.
With high reliability risk and capital costs yet to be incurred for backup
power, the door is not yet closed to considering mothballing Muskrat and
implementing more efficient alternatives.
The LIL risk especially, may be so great that the door could always be
wide open.
