This is Part I of a series on the financing of Muskrat Falls
and will focus on the 1150 km transmission line from Muskrat Falls, across the Strait of Belle Isle, and down the Island to Soldiers Pond, outside of St. John’s. Part
II will deal with the financing of the generation component. We will refer to
the line as the Labrador Island Link (LIL), which is the only high voltage
direct current (HVDC) line in the province. It is owned jointly by Emera and by
Nalcor.
The LIL’s direct costs, not including financing costs during
construction, amount to $3.7 B of the $10.1 B direct costs of the LIL and the
generation assets combined, representing 37% of the capital assets which
comprise the NL components of Muskrat Falls. Cost of financing during
construction brings the total LIL cost to $4,959 or 39% of the overall $12.7
billion estimated cost.
The Economics of Public Utilities
In a hydroelectric project like Muskrat Falls both
transmission and generation are capital intensive, which means that operating
and labour costs will be relatively low during operations while capital costs
will be high. For the LIL the main annual costs are the return on equity, the
interest on guaranteed debt, followed by depreciation and then operating and
maintenance costs (including fuel).
Public utilities often require large investments in order to
provide services to many users, such as transmission and communications lines.
They tend to come in large units, such as long distance transmission lines,
hydroelectric dams, and nuclear power stations and cannot easily be replicated,
certainly not in a small province. The LIL is a perfect example of such a large
indivisible unit which cannot be replicated without placing new towers and new
wires. Monopolies tend to form in an industry where it makes no sense to
duplicate infrastructure and where competing firms find it hard to gain access.
In order to control such monopolies governments establish public utility
tribunals to protect consumers and to simulate the impact of competition.
There is a balancing act that public utility boards must
achieve in keeping rates affordable for consumers while at the same time
allowing investors a competitive rate of return, sufficient to encourage the
large investment in infrastructure that is necessary. Power rates need to be
affordable to consumers yet high enough to cover costs, including a return on
equity investment.
Public utilities boards set rates through a hearing process
which involves a lot of technical data, including demand projections and
projections of costs. Fuel costs must be estimated, along with labour costs and
other operating costs. The cost of borrowed capital is estimated, based on
projected borrowing and forecasts of the interest cost which must be incurred.
The concept of a “test year” is used to avoid having to
undertake costly hearings too frequently. Included in the rate-setting exercise
is an estimate of how high the return on equity (ROE) must be to ensure the
investment capital is forthcoming. The estimate is comprised of a risk free
component which is normally 30 year government of Canada bonds. To this an
estimate is added an estimate of the risk premium appropriate for the electric
utility industry. The regulator compiles all of these costs together and sets
power rates to generate the allowed rate of return. These costs are compiled
annually and equity investors receive their return while those who invest in
bonds receive interest payments. The yearly costs are known as “revenue
requirements” and they include capital costs (ROE, depreciation, interest
payments) as well as labour costs and the cost of fuel purchases.
Public Utility Accounting
The methodology applied by regulators to calculate these
revenue requirements is known as “cost of service” regulation, because in each year
the costs are added and the ratepayer is called upon to pay for all costs
incurred, as verified by the regulator. The methodology used for Muskrat Falls’
generation assets is quite different, mainly because the province’s equity
return is not paid out on a yearly basis but is instead recovered over the 50
year life of the project, leading to rising payments toward the end of the
project’s life. This is in contrast to the normal declining revenue
requirements of a typical public utility following COS methodology, as
exemplified by the LIL. The reason for adopting this non-traditional approach
was to avoid rate shock. However, as we all know, this lofty goal was not
achieved and monumental rate shock is staring us all in the face.
The charts below show the impact of combining COS and non-COS
accounting. Chart 1 shows the full revenue requirements to be recovered from
customers on the Island for generation and transmission assets. Because
generation assets are more costly than the transmission assets, and also
require an equity rich (35%) capital structure, their revenue requirements
dominate the picture. Revenue requirements for Muskrat Falls will in the first
year more than double the $700 million in revenue requirements prior to Muskrat
Falls coming on stream, adding costs exceeding $800 million and raising utility
cost on the Island to a staggering $1.5 billion, higher than our spending on
education and 50% of health care spending. By 2030 these additional Muskrat
Falls costs will rise to $1 billion annually and by 2069 they will amount to
over $2.5 billion.
Each chart demonstrates the dominant importance of dividends
(ROE), depreciation and interest costs. Charts 1 and 2 show how ROE is the main
driver of rising costs.
Chart 2 shows the cost of service (COS) of the LIL which
follows a more traditional pattern, with slightly declining costs over the 50
year period. Unlike Charts 1 and 3 the cost of equity capital declines
throughout the 50 year period as equity investment is repaid and ROE declines
as a share of total revenue requirements for the LIL. 
Chart 3 shows costs associated with the Muskrat Falls site and the transmission line from Churchill Falls to Muskrat Falls, without the LIL costs. They rise very sharply over the period due to the back end loading of capital costs flowing from the ROE and redemption of equity.
In Part II of this series the rationale and implications of this departure from COS accounting will be explained.
Nalcor, which is the sole owner of the generation assets and
which shares ownership of the LIL with Emera, is a non-regulated crown
corporation. The generation assets are allowed to earn an 8.4% ROE, as set
forth in the Power Purchase Agreement. Equity investment in the LIL is allowed
to earn an ROE equal to the ROE earned by other regulated entities in NL,
currently 8.5%, even though LIL is not a regulated entity.
Federal Government Loan Guarantee: Who bears the risk?
The 2012 federal loan guarantee agreement provided $5 B in
loan financing and this amount was raised to $7.9 B in December of 2016. The
original agreement established minimum equity levels for each project
component. For the LIL the minimum equity was set at 25%, leaving 75% to be
financed by debt. For the generation assets the minimum equity was set much
higher, at 35%. The higher the equity share of the capital structure the more
protection there is for the bondholders. Shareholders are left bearing huge
risks because their investment will be the first to go into the void of
business failure.
This is based on the notion that the equity shareholder must
absorb the loss if the investment is not successful or if the entity is facing
bankruptcy. Under the loan guarantee the province of NL is out front, placing
its investment of $4 B at risk, with the federal government somewhat less
exposed. The 35% equity minimum for generation is a signal that the generation
component was always seen as the riskiest part of the project, riskier than the
LIL, for which 25% equity was required and riskier than the Maritime Link, for
which Emera was required to supply 30% of the risk capital.
The loan guarantee agreement and its call for a 10% higher
equity component for generation, 35% instead of 25%, was more than fully
justified. This has been borne out by the escalation of direct costs for
generation, which have risen by 123%, compared with 81% for the LIL. The
project delays have arisen largely because of problems at the site rather than
because of transmission issues. Earned progress on the LIL is 97.7% compared
with 78% at the generation site, an indicator of the slippage in the schedule
at the site.
The cost of equity capital is much higher than the cost of
borrowed funds. The Oversight Committee report for the period ending September
30, 2017 discloses that the average interest rate on the original 2012 $5 B
loan was 3.8%, while the effective rate on the 2016 guarantee was 2.9%. The
allowed ROE on the LIL is 8.5% while the ROE on generation assets is 8.4%. The
additional 10% of required equity adds to the capital cost of the generation
project by calling for funding an additional 10% of its capital cost with
equity, costing 8.4% rather than debt financing with a weighted average cost of
3.6%.
The federal loan guarantee was vital to the financing of the
Muskrat Falls project. The federal government made its financing contingent on
certain key conditions. One was the need for participation by Nova Scotia,
infusing the project with an inter-provincial rationale and tied to the closure
of coal-burning plants in Nova Scotia. The benefits to Nova Scotia claimed in
the 2010 Term Sheet were enhanced in subsequent negotiations. The original 20%
of Muskrat Falls power for Emera, in exchange for 20% of the total investment,
was improved in 2013 when the public utilities regulator in Nova Scotia
rejected the Term Sheet and demanded additional power at market rates.
Power purchase agreement pledged as collateral
The federal government also required a pledge of repayment
through a Power Purchase Agreement under which power consumers in NL would
repay the guaranteed loans. The PPA was a take-or-pay contract between Nalcor
Energy and its wholly owned subsidiary NL Hydro. In addition the province
undertook to provide a completion guarantee which committed the province to
inject any additional funds required in the form of equity. In the event of
further cost escalation it would be the province who would be most exposed,
injecting new funds if necessary and agreeing to bear the full loss of its
equity in the event the project encountered stormy weather.
The province also enacted new legislation to ensure that
consumers in the province would not be able to seek alternative sources of
power, whether through buying from outside sources, once the Island was interconnected,
or by buying from independent power producers in the province. The legislation
forced consumers to deal with Nalcor and strengthened its existing monopoly
powers. It is hard to imagine more regressive legislation strengthening the
evils of monopoly power while exempting Nalcor from the jurisdiction of the
PUB. The legislation is also in defiance of the Open Access policies mandated
by the American regulator, the Federal Energy Regulatory Commission (FERC). If
Nalcor plans to export power it has to be in compliance with FERC rules and the
legislation is an affront to those rules.
Limits to Revenue Recovery
Legislation can only go so far in removing consumer choice. In
a rapidly changing energy world consumers have more and more options to substitute
alternative forms of energy other than electricity. The first electricity use
to be displaced will be inefficient resistance-type space heating as people
introduce heat pumps and engage in serious energy efficiency. With the prospect
of doubling of rates and with advance notice to consumers of major rate
escalation it is likely that demand for electricity will collapse. New research by Dr. James Feehan at Memorial provides an estimate of long term electricity
demand, using NL data, showing that consumers are likely to demonstrate an
energetic resistance to rate increases
(https://www.sciencedirect.com/science/article/pii/S0957178717301340).
Export revenues from Muskrat Falls are likely to be low. In
fact Nalcor has assumed small export revenues in their response to ATIPPA
requests. Revenues from domestic sales and from power exports will not come
close to paying the substantial obligations the province has incurred.
Dividends: the Impossible DreamThe PUB can establish an allowed rate of return on equity but they can offer no guarantee that it will be achieved by increasing rates. If consumers are determined to find other substitutes they will simply refuse to buy Muskrat Falls power. This is not just likely; it is probable. Demand will collapse and revenues may decrease, rather than increase. Attempts to raise rates to offset this collapse will be counterproductive. The result is that the 8.5% ROE on the LIL may not be achieved nor will the 8.4% ROE on generation assets. In fact PlanetNL in Can Muskrat Falls Float After a Bailout? has shown that the revenues from Muskrat Falls may not even cover interest cost, let alone ROE. This means that the large investments, by our province, by Emera and by the federal government, are in jeopardy. Revenues are unlikely to come close to covering costs.
The promised dividends spoken of by former CEO Ed Martin, by
Premiers Dunderdale and Marshall, by former Energy Minister Kennedy and by
Finance Minister Wiseman may be simply a delusion, a mirage.
We turn in Part II to the financing model used to finance the
generation assets and to how this model deals with power rates, dividends and
the uncertain prospect for placing Muskrat Falls on a sound footing.
David Vardy
