This is the sequel to my post of March 19, 2018 on the
financing of Muskrat Falls called The Impossible Dream Part I: Financing The
Labrador Transmission Link. In this post I measure the increased costs
associated with Muskrat Falls and discuss the impact on rates and the potential
for rate mitigation.
Rate Mitigation
A recent Telegram article (“Power Rate Options Still Unclear”,
Telegram, May 5, 2018) . refers to “$60 million to $70 million required to
decrease customer rates by one cent per kilowatt hour”. This suggests that, if
rates were increased from 12 cents to 17 cents, revenues would rise by $300
million to $420 million. This is highly unrealistic.
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| Photo Credit: NTV |
In order to save $147 million in fuel cost we have added $786
million in other costs, mostly capital costs. This is the tragedy of Muskrat
Falls. What does that say about the cost benefit analysis presented in 2012 to
the PUB? Is it better to pay our money to Wall Street investors than to the Oil
Barons? Remember how we were going to keep oil dollars within the province? The
fuel cost has been reduced but the increased capital costs are monumental!
The fuel savings depend upon the reliability of power from
Muskrat Falls. With this in mind I have assumed fuel savings of $147 million,
rather than the full $221 million used by Nalcor in its 2019 Test Year
presented to the PUB in its general rate application.
The PUB is currently considering rate options whereby rates
are adjusted upward in advance of Muskrat Falls. The focus is one billion
kilowatt hours of Recall power, an amount which is shrinking as additional data
centres emerge to absorb the remaining surplus power from the 300 MW provided
under the Churchill Falls contract. This power will displace Holyrood power and
build a deferral account to offset the high costs of Muskrat Falls. After
transmission costs are paid little money will remain for the deferral account.
Research published by Dr. James Feehan at Memorial indicates
that price elasticity of demand for power is likely to be high. This means that
rate increases will shrink demand. It also means that revenues from power sales
may also drop when rates increase. Instead of raising rates we might be well
advised, as Dr. Feehan proposes, to drop rates, as paradoxical as that may
sound.
If demand is highly elastic then an increase in rates will not
increase revenues. Instead revenues will fall. It is highly likely that if
rates increase to 17 cents per kilowatt hour those revenues will remain at
their present level, around $700 million, leaving the total increase of $786
million of incremental costs stranded, without offsetting revenues.
“Rate mitigation” is
based on relatively inelastic demand, which does not square with the facts. The
concept of “rate mitigation” is a chimera because it assumes that ratepayers
can absorb additional costs. It also assumes that pots of money are lying
around unused and that such mitigation can be accomplished without impacting on
social programs.
If rate increases fail to generate additional revenue can we
look to export sales for salvation? PlanetNL has undertaken research on energy
markets and transmission costs. He concludes that net revenues will be small,
after inter-state and inter-provincial transmission costs are deducted. Nalcor
Energy Marketing achieved average sale price for CFLco recall power of 3.1
cents per kilowatt hour in 2017 in export markets, according to their annual
report. After deducting all costs the
net profit was one cent per kilowatt hour.
Rate comparisons with Nova Scotia are not valid because of our
much greater reliance on electricity for space heating. We can shed space
heating load quite easily when rates go up, adding greater elasticity to
consumer demand.
If the ratepayer cannot pay more can we expect the taxpayer to
be any better able to meet the increased burden at a time when our combined
operating and capital budget is close to $2 billion?
If not then where do we go? If we go on bended knee to Ottawa
what pound of flesh will they demand?
Revealing the Hidden Costs of Deferral Accounting
The cost calculations going into Muskrat Falls are a Witches
Brew, a concatenation defined by the Cambridge Dictionary as a mixture of
“unpleasant or dangerous” things. It is a hybrid of normal and “creative”
accounting.
Crown corporations across Canada are seeking “creative” ways
to push costs into the future. In Ontario the Auditor General has taken issue
with the scheme to reduce power bills by 25%. (“Bad Books”, Globe and Mail 21
April 2018), Auditor General Bonnie Lysyk reported that the Fair Hydro Plan was
set up to defer expenses and to securitize unbilled revenues. She said that
government had embarked on “creative accounting” to keep the shortfall between
rate revenues and costs off the accounts of the province. Similar efforts have
been made in Manitoba and in British Columbia, where crown-owned utilities
attempt to secure short term gain for long term pain. Are the byzantine
arrangements by which Muskrat Falls is financed equally at variance with
established accounting standards?
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| David Vardy |
In public utility accounting the term “revenue requirements”
includes all annual costs associated with a project or service. This includes
the cost of capital: interest payments, return on equity and depreciation. It
also includes fuel cost and the cost of operations and maintenance. In a highly
capital intensive project the operating costs tend to be low relative to the
capital cost. Fuel cost savings were touted as the big advantage of Muskrat
Falls. How do these fuel savings compare with the incremental capital cost? We
provide an answer to this question.
In this post we focus on the “generation assets” which Nalcor
has defined to include the generating facility at Muskrat Falls and the
transmission line from Muskrat Falls to Churchill Falls. As we saw in Part 1 of
this series the Labrador Island Link (LIL) is being financed through a
conventional cost of service (COS) methodology, which means that all costs are
charged to consumers in the year in which the costs are incurred. COS
methodology generally results in declining unit costs over time.
In order to avoid rate shock Nalcor decided to use a different
approach to the expensing of costs, one which defers the return on equity
investment into the future. This is done by spreading costs over the life of the
generation assets (50 years) by keeping unit costs level in real terms. I will
refer to this methodology as the “cost deferral approach” (CDA), in contrast
with COS. It depends upon increasing future power consumption because it defers
a large amount of costs. It has the effect of shifting costs to future
generations by expensing educing present costs by deferring the expensing of
present costs relating to the ROE on generation assets.
The purpose in adopting this approach was to avoid shock by
mitigating the immediate burden of higher costs. It was recognized that the
full output of Muskrat Falls would not be needed at the outset but it was
assumed that demand would grow. The basis for assuming growth in demand is
unclear, given the rather bleak demographic projections which were available at
the time of sanction. If costs were stated using COS methodology it is highly
unlikely this project would have seen the light of day. The cost deferral
approach served as a camouflage to hide the full impact of the project. When
capital costs more than doubled the magnitude of the deferral became more
egregious.
Based on a hybrid of CDA and COS revenue requirements escalate
dramatically, even though real unit costs remain constant, somewhat
paradoxically. If consumption does not increase in future then costs will not
be recovered. With the prospect of doubling in rates it is unlikely that
consumption will rise sufficiently for repayment of debt and recovery of costs.
It is also highly unlikely that the province’s equity will be recovered or that
a return on equity will be paid by Nalcor.
The accounts for Muskrat Falls are a curious hybrid of
traditional and “creative” methodologies. When COS and cost deferral are
combined we end up with meaningless numbers. I have attempted to place the
revenue requirements on a cost of service basis, in an attempt to determine
exactly how much revenue needs to be generated to cover costs. The data upon
which I will draw are Nalcor data. Nalcor’s hybrid cost data show revenue requirements
escalating from $809 million in 2021, to over $1 billion in 2030 and to $2.6
billion in 2069! Only by shifting to full COS accounting can we understand the
impact of the project.
The heart of the issue is the treatment of provincial equity
investment in generation assets. Apart from the difficulty of comparing apples
and oranges the most compelling argument for restating all costs in the
framework of COS is that the cost of equity capital invested by the province is
inescapable. The interest must be paid even though Nalcor’s obligation to pay
may be deferred. The interest cost on $4 billion, without provision for risk
premium and without making provision for AFUDC, works out to about $160
million.
The risk premium adds a similar amount. Any reckoning of the
annual cost to the citizens of the province must include, at a minimum, the
cost of the capital borrowed injected as “equity” in the project. No measure of
annual cost is complete without a recognition of the real cost of money
borrowed by the province. The weighted average interest rate of public fixed
rate debt issues (not including debt issues of or on behalf of government
business enterprises, agencies or boards) is approximately 4.6% but the
effective long term borrowing cost in recent years has been lower.
The cost of equity capital for financing of generation assets
is relatively higher than for the Labrador Island Link (LIL). The minimum ratio
of equity to total cost required for generation assets is 35%, compared with
25% for the LIL. Equity is more costly than debt, usually double or more.
Equity financing for generation assets is projected to be more than 41%, well
above the 35% minimum. This translates into unavoidable costs for a province
with a large gross debt and borrowing heavily each year, both for operating and
capital account.
Nalcor’s response to my access to information request
(PB-242-2018) provides Nalcor Energy’s projection of revenue requirements for
2021-2070 relating to each of the generation site, the transmission line from
Muskrat Falls to Churchill Falls (Labrador Transmission Assets, LTA) and the
LIL. These numbers add to $809 million in 2021. The methodology used in
converting all costs to a common COS base is shown in the Appendix. When I
transform the cost numbers using accepted COS methodology the following
conclusions emerge:
A. Total investment
in the project becomes $13.7 billion, instead of $12.7 billion.
B. The $809 million
in annual cost becomes $1,138 million.
C. When the ROE is
adjusted by removing the equity risk premium the $1138 million drops to $933
million, up by $124 million from $809 million. What I have added is the real
cost of borrowed “equity” funds to the province, recognizing that bondholders
will not forfeit or delay interest payments when they are due.
D. Muskrat Falls may
produce fuel savings and when adjusted for savings of $147 million the new
annual costs become $786 million.
E. After deducting
fuel cost the remaining revenue requirements for the Island electrical system
will be $1.5 billion, up from $700 million currently.
Conclusion
The real costs of Muskrat Falls are higher than stated and
cannot be recovered through rates. Even if rates are increased to 17 cents per
kilowatt hour the unrecovered costs will remain at close to $800 million, much
higher than the $400 million which has been used in public discussion.
The real costs of the project are much higher than reported
through hybrid accounting methodology. They are $13.7 billion, $1 billion
higher than the reported $12.7 billion.
Having refused to stop the project because of the contractual
commitments and sunk costs will we instead be forced to shut it down because we
cannot afford to operate it? Remember there were those of us who said that sunk
costs were irrelevant and that only future costs mattered?
Perhaps part of the solution is lower, rather than higher,
power rates!!
Why are these two issues of designing power rates and
developing options to recover costs not part of the mandate of the Muskrat
Falls Inquiry? Are they not the fundamental issues that should be at the heart
of the Inquiry?
David Vardy
Technical Appendix
Calculating the Hidden Costs of Deferral Accounting
Interest during construction (IDC) recognizes the time value
of money after money has been invested and before the asset is commissioned for
use. IDC represents the accumulation of interest on borrowed funds invested in
the project. Allowance for Funds used during construction (AFUDC) represents
interest on equity capital, as opposed to debt. Both IDC and AFUDC are
accumulated on the LIL, which is accounted for under COS methodology. IDC is
recognized for generation assets under the cost deferral approach (CDA) but
AFUDC is not recorded.
In my attempt to bring all costs within the COS framework I
have calculated how much should be added to reflect the time value of equity
financing for generation assets, commensurate with those accrued for
transmission assets. In moving from CDA to COS we need to take account of
AFUDC, which has the effect of adding close to $1 billion to project costs.
In my calculations I make the following adjustments to this
estimate of the annual cost of the project:
1. Increased province equity in generation
assets by $963 million, raising total the total investment in the project to
$13,683. To calculate the increased provincial equity we estimated AFUDC in
generation assets in two steps. In the first AFUDC for the LIL was scaled up
based on the ratio of generation costs to transmission costs using direct
costs, before financing costs are added. This added $754 million. In the second
step this estimate was scaled up to recognize the higher proportion of equity
in generation assets, raising the $754 million to $964 million.
2. The $964 million raised provincial
equity from $3,154 million to $4,118 million. Applying the ROE estimated by
Nalcor for transmission investments to this $4,118 million produced an estimate
of $343 million for the ROE on generation assets, raising the amount reported
by Nalcor ($14 million) by $329 million.
3. The additional $329 million in ROE raises
the total revenue requirement for 2021 from $809 million to $1,138 million.
4. This increase of $329 million in ROE for
generation assets is based on the allowed rate of return of 8.4% provided in
the power purchase agreements in combination with the rate of return allowed
for LIL. The ROE on the LIL is linked with that allowed for NP by the PUB,
currently 8.5%. If we assume the long term borrowing cost for the province is
4.2% then this leaves another 4.2-4.3% for the risk premium. There is no
question that Nalcor is imposing large risks on the province. However, the
direct immediate cost to the province of injecting $4.9 billion in equity is in
the order of 50% of the allowed ROE. I have therefore reduced the ROE to the
province by $205 million, which reduces revenue requirements to $933 million.
The weighted average interest rate of public fixed rate debt issues not
including debt issues of or on behalf of government business enterprises,
agencies or boards is approximately 4.6% but the long term borrowing rate has
been below this level in recent years.
5. The overall result of these
calculations is to raise the revenue requirement from the $809 million reported
by Nalcor to $933 million, an additional $124 million.
6.
Finally I have made an adjustment to allow for fuel savings by taking
the number provided by NL Hydro to the PUB in the general rate application for
the 2019 Test Year, namely $221 million and reducing it by one third to reflect
reliability issues associated with Muskrat Falls. This amount of $147 million,
when deducted from $ million, results in a revised revenue requirement of $786
million. This more than doubles current revenue requirements to $1.5 billion,
which is similar in magnitude to our education cost and to the cost of
servicing the public debt.
