Clean Energy Council
Financing Impacts of amendments to the
Renewable Energy Target
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Irrespective of which reduction
scenario might ultimately be
legislated, sovereign uncertainty
raises compelling reasons to doubt
the stability and longevity of a
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The RET Review Report dismisses sovereign risk, overlooking how integral assumptions and
modelling in relation to REC pricing based on the current RET scheme are to the financial viability of
existing operators and new entrants.
There is a risk for the Australian Government that the policy objective of achieving even reduced
targets might not be met because of the impacts resulting from sovereign risk associated with a
reduction to the RET.
Any substantial reduction of the RET will invariably lead to REC prices being sufficiently lower
than prices modelled for operating projects and projects under development for the purposes
of equity and debt financing. There is general consensus among energy market forecasters that
REC prices will fall on average by between 10% - 30%.1
With any reduction to the RET, the scarcity and costs of capital (equity and debt) will increase
in such a way as to make many existing and future projects financially unviable. For both
project and corporate finance arrangements, any substantial reduction to the RET will certainly
trigger a review of existing funding arrangements by lenders. The cost of capital for equity is likely to
be higher, reflecting the higher cost and risk profile of developing a renewable energy project in
Australia with lower REC prices.
A reduction in the RET is likely to expose projects to greater merchant risk as it will fundamentally
change the operation of the wholesale REC market. A lower RET target is likely to suppress
merchant REC prices and increased volatility in the merchant REC price will pose a significant risk to
A reduction to the RET will make obtaining a long-term PPA from electricity retailers increasingly
difficult. Without longer-term off-take agreements, new entrants are unlikely to be able to obtain
debt financing on reasonable terms.
Where electricity retailers do enter into off-take agreements, it is likely that project sponsors will likely
be required to take some share of any future change in law risk. Exposure to change in law risk
reduces the predictability of revenues and reduces the bankability of the off-take agreement.
The impact on PPAs is not the direct impact of any change in law, but the indirect impact as these
PPAs expire, where it is expected that retailers will be less willing to agree to further PPA
arrangements and projects will invariably have to operate on a merchant basis with lower REC prices.
The vast majority of existing projects will be up for refinancing over the period 2016-2018. Existing
projects might not be able to meet the minimum financing requirements based on the revised
set of risk assumptions and parameters.
1 See ACIL Allen Consulting modelling for RET Review Report and ROAM modelling for the Clean Energy Council.
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Any reduction to the RET will trigger a set of review and default mechanisms in debt financing
agreements which could lead to actual default and, potentially, an enforcement scenario. In such
circumstances, equity will likely take a significant write-down (even up to 100%) on the value of their
investment and lenders could be left with renewable projects as distressed assets.
A reduction to the RET may see cash sweeps by lenders persisting for a significant period, putting
increased financial pressure on equity.
There are likely to be legal challenges to any legislative change made to the RET which results
in adverse financial impacts on renewable energy operators and developers.
By necessity, any compensation and transitional assistance regime will need to be designed for the
specific financial arrangements of each and every renewable energy project.
Designing and implementing compensation or transitional assistance will involve significant
inherent complexities and policy issues that could potentially undermine the overall effectiveness
and efficiency of a reduced RET.
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Introduction ........................................................................................................................................................ 1
RET Review ............................................................................................................................................................. 2
Impact of sovereign and regulatory risks following a reduction to the RET ...................................................... 3
Impact on equity and debt financing ........................................................................................................................ 6
Impact of merchant price risk on projects ................................................................................................................ 8
Impact on forward contracting arrangements ........................................................................................................ 10
Policy risk .............................................................................................................................................................. 10
Impact of sovereign and legal risks on financing and contractual arrangements ........................................... 11
Off-take Agreements .............................................................................................................................................. 12
Financing Agreements ........................................................................................................................................... 13
Refinancing risk ..................................................................................................................................................... 15
Risk of default ........................................................................................................................................................ 16
Financing impacts of a reduced RET ..................................................................................................................... 17
Issues in relation to compensation .................................................................................................................. 18
Clarifying the legal and policy grounds for any compensation ............................................................................... 19
Determining threshold for compensation ............................................................................................................... 21
Form and timing of compensation .......................................................................................................................... 22
In this report prepared for the Clean Energy
Council we set out the potential impacts of the
sovereign risks arising from any legislative
amendments to the Large-Scale Renewable
Energy Target scheme (RET)2 established under
the Renewable Energy (Electricity) Act 2000 (Cth)
(the Act). In particular, we examine the potential
impacts of any substantial reduction in the RET
scheme in light of the recommendations put
forward by the ad-hoc Expert Panel appointed by
the Australian Government (Expert Panel).
2 We have not considered in this report the impact of the Expert Panel's
recommendations in relation to the Small-scale Renewable Energy Scheme on
small-scale renewable energy projects, in particular rooftop solar PV.
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In this report, we examine the sovereign risks that we consider are likely to arise in relation to any
substantial reduction of the RET, and how these risks manifest themselves in relation to financial and
contractual arrangements that underpin existing and future large-scale renewable energy projects that are
developed, financed and operated under the RET.
We also examine the issues and complexity associated with designing and implementing any
compensation regime to compensate incumbent renewable energy operators, and any new market
entrants under any reduced target scenarios, for the impact of any amendments to the RET on existing
projects, or in relation to sunk costs of projects under development.
On 28 August 2014, the Expert Panel released its report and recommendations (RET Review Report).
While the RET Review Report considers a number of scenarios for amending the RET (including an
outright repeal of the RET Act), for the purposes of this report we have focused on the impacts of any
reduction of the RET - either on a fixed target basis or with rolling annual targets.
Impact of sovereign and
regulatory risks following a
reduction to the RET
The Government's ad-hoc RET Review has
created a high degree of uncertainty over the
future of the RET. This uncertainty is likely
to have a significant adverse impact on investor
confidence in renewable energy projects in
Australia, regardless of the extent to which the
RET is reduced.
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The RET Review Report identifies sovereign risk as traditionally referring "to the risk of a government
defaulting on loan obligations (sovereign credit risk)" but concedes that "the term is now used more broadly
to refer to the effect of changes to government policy on both existing and future private investment."3
In the end, the Expert Panel considers that any changes to the RET are "more correctly characterised as
regulatory risk" rather than sovereign risk on the basis that:
such risks are "always present";
while certainty of regulatory settings is an important facilitator of investment in long-term infrastructure,
"this does not imply that regulations should be set in stone";
notwithstanding that renewable energy project owners invested in good faith and in accordance with a
government policy that had bipartisan support, significant change to the RET should have been
anticipated by project owners; and
any significant change to the RET would not represent "an inappropriate level of risk for investors."4
The only scenario in which the Expert Panel considers that amendment to the RET "would create significant
adverse financial implications for existing investors in renewable generation" is the option of an immediate
repeal and winding-up of the RET. As a result, the Expert Panel recommends the large-scale RET should
continue, but in a modified form with reduced targets.
The analysis in the RET Review Report in relation to sovereign and regulatory risk is, however, deficient in
one key respect: it would appear the Expert Panel has failed to properly consider the impact of amendments
to the RET, based on the modelled scenarios, on the ability to refinance equity and debt for existing
renewable projects and to obtain equity and debt finance for new renewable generation (particularly under a
"real" 20% target scenario with rolling targets).
The large upfront capital expenditure required for large scale renewable projects means investors and debt
financiers require predicable long term cash flows in order to make investment decisions and recoup the
investment over a longer time horizon. Irrespective of which reduction scenario might ultimately be
legislated, there are compelling reasons to doubt the stability and longevity of the RET scheme
which is a direct result of sovereign uncertainty. Moreover, any substantial reduction of the RET will
invariably lead to REC prices being sufficiently lower than prices modelled for operating projects
and projects under development for the purposes of equity and debt financing.
To dismiss sovereign risk "as ever" present and not "an inappropriate level of risk for investors", overlooks
how integral assumptions and modelling in relation to REC pricing based on the current RET
scheme are to the financial viability of existing operators and new entrants.
In Australia, the sale of RECs accounts for between 40% - 50% of project's operating revenue. As a result,
unscheduled reductions or changes to the RET will not just have impact on future investment, but will
undermine the financial viability of existing operators. If the impact of changes on existing projects is not
appropriately managed through compensation and transitional arrangements, the sovereign regulatory risk
will increase significantly.
3 RET Review Report, page 57.
4 RET Review Report, pages 57-58.
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Investors and credit rating agencies assume that once a policy is approved, governments will not apply
targeted retroactive changes that affect existing projects. A change in regulatory regime that reduces a
project's support during the life of the debt will trigger revaluation of the project's credit worthiness and may
lead to downgrades. Credit agencies warn that high regulatory uncertainty can preclude projects from
obtaining investment-grade level debt ratings.
As we discuss in section 4 below, there are likely to be legal challenges to any legislative change made to
the RET which results in adverse financial impacts on renewable energy operators and developers. By
necessity, any compensation and transitional assistance regime will need to be designed for the
specific financial arrangements of each and every renewable energy project. This process however,
comes with its own inherent complexity and risks. Calculating and assessing compensation claims can be
exceedingly complicated and administratively burdensome (as was demonstrated with compensation and
transitional assistance arrangements for emissions-intensive trade-exposed industries and coal-fired
generators under the now repealed carbon pricing mechanism). It will be necessary to examine each claim
on an individual basis so as to prevent windfall gains or losses for projects and to ensure that any
compensation regime is operating as efficiently and not leading to perverse outcomes. The complexities and
issues associated with compensating existing operators and project developers are addressed further in
section 4 below.
From a legal and contractual perspective, the sovereign risk associated with any significant reduction to the
RET will manifest itself in a variety of ways in the context of the financing and contractual arrangements in
place for both contracted projects (financed under non-recourse project finance) or projects trading as
merchant power stations (financed on balance sheet or with corporate debt).
These impacts include the following:
Impact on debt and equity financing
Refinancing of existing projects is likely to be more difficult under a reduced RET and invariably debt finance
will be more expensive as a result. Debt financiers and equity investors will also need to be comfortable with the
level of any compensation or price intervention mechanisms included to mitigate adverse impacts on new
entrants, or as part of any compensation arrangements.
Impact of merchant price risk on projects
A reduced RET will result in lower demand for RECs. REC prices out to 2020, and then to 2030, will be
lower than what they would be under the current RET. The Expert Panel's own modelling from ACIL Allen
Consulting, as well as modelling by ROAM, Bloomberg New Energy Finance, and others, all show lower
REC prices under the reduced targets. Accordingly, existing projects will be under increasing financial
pressure when exposed to merchant electricity prices during any uncontracted period - immediately for
merchant projects and at the end of current power purchase agreements (PPAs) for contracted projects.
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Impact on forward contracting arrangements
Existing operators and project developers are likely to struggle to obtain longer term off-take agreements
from electricity retailers and other liable entities given the history of policy and price uncertainty - and
particularly where any reduced RET uses rolling targets set annually. If retailers do offer PPAs, it is highly
likely that the project developer will be required to share some of any future change of law risk. Given that
change in law risk is a "wild card" (i.e. there is no way to know whether the risk will actually materialise or, if
it does, what the extent of the changes will be), lenders will have little appetite for accepting such a risk and
will, in turn, increase cost of debt financing or expect project owners to contribute more equity into projects.
Impact on policy objectives
These increased financial pressures on equity investors and higher debt financing costs could lead to default
by existing operators and is likely to discourage new market entrants from developing additional renewable
generation. As a result, there is a risk that any reduced targets will not be achieved. Increasing equity and
financing costs could lead to projects falling over and there not being a new build of additional capacity to
meet the reduced target.
Each of these risks is addressed in turn below.
Impact on equity and debt financing
Under a reduced RET, the cost of financing (both debt and equity) is likely to increase significantly due to lower
REC prices, an inability to reasonably forecast price scenarios and the perception of greater regulatory
uncertainty - particularly where targets are set on a rolling annual basis.
This will adversely impact on the ability of:
existing projects to service current corporate or project-level debt arrangements and their ability to
new projects to obtain initial equity and debt financing.
With any reduction to the RET, the scarcity and costs of capital (equity and debt) will increase in
such a way as to make many existing and future projects potentially financially unviable.
Impact on existing projects
For existing operators, any reduction to the RET is likely to adversely impact their ability to refinance and will
certainly increase the cost of any future finance.
For both project and corporate finance arrangements, any substantial reduction to the RET will
certainly trigger a review of existing funding arrangements by lenders. In such circumstances, lenders
will update their assumptions on risk and look to restructure the debt sizing to take into account the changed
risk profile of the project. The key risks for financiers will be the level of exposure of a project to lower
merchant REC prices. For projects with PPAs, financiers will consider their level of exposure to merchant
REC pricing risk in the tail period of the notional tenor of the loan; for uncontracted projects, the remaining
life of the project and the prospects of obtaining any off-take agreement of bankable tenor. For all projects
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under a reduced RET, financiers will be determining the ability of the project to service its level of debt given
lower project revenue from lower REC prices.
Given the shorter tenor of loans given by Australian banks, renewable energy projects typically need to be
refinanced every five to seven years. This means that the vast majority of existing projects will be up
for refinancing over the period 2016-2018.
Accordingly, there is a risk that existing projects might not be able to meet the minimum financing
requirements based on the revised set of risk assumptions and parameters. In such a scenario, automatic
and mandatory prepayment of the loan might be required until the debt ratios are within acceptable
levels. This means equity will need to contribute more capital in order to reduce the debt levels or risk
defaulting on the loan, which puts increasing pressure on equity to continue financing projects beyond what
had been modelled at the time of reaching financial close on these projects.
Moreover, debt gearing ratios are likely to worsen as lenders become more reluctant to lend on a
highly geared basis (typically renewable energy projects in Australia are debt financed on a gearing
of 60% to 70%) of loan. This more cautious approach is also likely to manifest in shortened notional
amortisation times and higher debt service cover ratios (DSCR). Lower gearing ratios will place pressure on
equity to contribute further funding, while a higher DSCR places greater stress on equity in circumstances
where operating revenue is expected to be falling (due to lower REC prices). From a lender's perspective,
these levers are necessary to mitigate against the higher risk of default, however, they will need to be finely
tuned to ensure operators remain financially viable.
More generally, both Australian and foreign banks are likely to be more risk averse given the ongoing
perceptions of regulatory uncertainty and price uncertainty under rolling annual targets. Foreign banks in
particular might exit the market and existing and new projects will likely only to be able to obtain financing
from a smaller pool of existing lenders. This will reduce liquidity in the refinancing market, which will further
drive up refinancing costs.
Impact on new projects
Under the fixed "real" 20% scenario, explored by the panel, or the scenario with a rolling annual target
(assuming they both result in approximately 20% by 2020) approximately 3,100 MW of new and additional
installed capacity would need to be built by 2020 to meet the reduced targets.
As with existing projects, it is likely that any new project looking to be developed under a lower RET will face
higher costs and more onerous terms for any debt financing. The cost of capital for equity is also likely to
be higher, reflecting the higher cost and risk profile of developing a renewable energy project in
Australia with lower REC prices.
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Based on the way in which renewable energy projects have been project financed in Australia to date, it
would be expected that any new project would need to have a bankable longer tenor PPA in order to obtain
reasonable cost debt financing. If bankable revenue under a PPA is less than 10 to 15 years, the financing
costs rise. However, electricity retailers are unlikely to enter into any long-term off-takes agreements given
the regulatory uncertainty and the short-term incremental nature of increasing targets or holding them
constant with any reduction to the RET.
As a result, new projects are likely to have to operate:
under shorter term off-take agreements; or
entirely on a merchant basis (i.e. exposed to both wholesale electricity and REC prices).
In either circumstance, any debt financing is likely to include:
shorter tenors (to reflect the lower level of contract revenue);
lower debt to equity ratios (typically currently 70/30 gearing which could go to 50/50 or lower);
shorter notional loan amortisation periods (typically currently 17 to 18 years); and
more restrictive financial covenants, such as higher DSCRs.
The overall impact will be that equity will be required to contribute significantly more capital in order to have
new projects financed and constructed.
Impact of merchant price risk on projects
A reduction in the RET is likely to expose projects to greater merchant risk as it will fundamentally
change the operation of the wholesale REC market. In particular, merchant price risk will increase as a
lower spot REC prices due to lower demand for RECs and strategic use of existing surplus holdings by
exposure to spot power prices for longer uncontracted periods (given the prospect of shorter offtake
agreement terms and potential difficulty in hedging).
Merchant generators which operate without a long-term off-take agreement will be most vulnerable to the
increase in merchant price risk. As the RET Review Report notes, there is "a strong possibility that owners
of these projects [without LGCs or off-take agreements] would not remain solvent."5 The RET Review
Report goes on to say that "these assets would be sold at a loss but would then continue to operate under
new financing and ownership structures." 6
Most significantly, the Expert Panel wrongly understands the nature of this merchant risk on renewable
energy generators. It assumes that - in recommending that targets be set annually rather than fixed -
"renewable energy investors [are exposed] to the same market risk (that future levels of electricity demand
are unknown) that other investors in the sector currently face."7 The RET Review Report fails to
5 RET Review Report, page 57.
6 RET Review Report, page 57.
7 RET Review Report, page iv.
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recognise that a lower RET target is likely to suppress merchant REC prices to such an extent that
the bundled merchant price is well below breakeven price for operators and financially unattractive
for any new owners. Merchant projects may not achieve such a bundled price under the reduction options
recommended in the RET Review Report (particularly those with rolling targets), and, as such, are at
increased risk of financial distress and default on debt.
Operators with existing off-take agreements may struggle to enter into a new off-take agreement, leaving
them exposed to merchant pricing. Existing operators will also be impacted by increasing financing costs,
which are influenced by lower merchant REC prices.
The impact of merchant pricing is notoriously difficult to forecast with any certainty. For instance,
ACIL Allen Consulting's model predicts that under the losed to new entrants scenario, the price of RECs is
likely to oscillate between the two extremes of near zero and the penalty price due to strategic use of
existing and future surplus holdings by electricity retailers and other liable entities. A price of near zero is
possible for renewable energy projects given their low marginal operating costs. Irrespective of the impact of
the price movements, the increased volatility in the merchant REC price will pose a significant risk to
existing projects. The effect is particularly more acute for uncontracted (merchant) projects. However, even
existing contracted projects will be impacted as the cost of financing is adjusted to reflect increased
merchant exposure in any uncontracted tail.
The increased volatility will also make it increasingly difficult for new projects to enter the market on a
merchant basis as the revenue stream is likely to be viewed by equity as too unpredictable to fund on
balance sheet and because many operators of merchant projects in Australia will already be under financial
stress because of the impact on their existing merchant portfolio.
Notwithstanding the extreme binary case examined in ACIL Allen Consulting's modelling, there appears to
be a general consensus among energy market forecasters that REC prices will fall on average by
between 10% - 30%.8 The low prices for RECs reduces revenues and creates a risk that projects may not
be able to meet their debt servicing obligations if operating on a merchant basis or once the term of the offtake
Wholesale power prices are expected to increase with any reduction to the RET. This is because renewable
generators put downward pressure on wholesale electricity prices as they have a much lower (or near zero)
short run marginal cost compared to thermal generators. As noted before, there is considerable variability in
forecasts. It is clear, however, that the increased wholesale price will not be sufficient to offset the reduction
in REC prices. In any event - as outlined above - the increase in volatility will result in an adjustment to
financing arrangements which will be more conservatively structured and costly, in order to account for the
increased risk of not being able to service the debt.
The merchant REC price risk is likely to be most pronounced where a target is set with rolling annual targets
as the future demand for RECs will by design be uncertain from year to year and therefore difficult to
8 See ACIL Allen Consulting modelling for RET Review Report and ROAM modelling for the Clean Energy Council.
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Impact on forward contracting arrangements
A reduction to the RET will make obtaining- a long-term PPA from electricity retailers and other liable entities
for a bundled electricity and REC price increasingly difficult - and highly unlikely under a rolling target
scenario. The increase in sovereign risk means that electricity retailers and other liable entities have less
incentive to enter into off-take agreements in excess of five or seven years. Without longer-term off-take
agreements, new entrants are unlikely to be able to obtain debt financing (or at least on reasonable terms).
In the event that electricity retailers do enter into off-take agreements, it is likely that project sponsors will
likely be required to take some share of any future change in law risk. (This might be done in a number of
ways as discussed in section 3 below.) The consequence, however, is the same: exposure to change in
law risk reduces the predictability of revenues and reduces the bankability of the off-take agreement.
This, in turn, increases debt costs and places greater pressure on equity to contribute more capital.
Off-take agreements for most of the existing renewable energy projects in Australia will expire within the
next 10 to 12 years (with a handful that will run until 2023 to 2025). This means that projects will be required
to enter into new off-take agreements for the remaining life of the project until 2030 (if possible) or be
exposed to merchant pricing. For existing operators and new entrants, the inability to secure (further)
long-term off-take agreements is likely to adverse impact their financial viability, particularly if they
have a long merchant tail during the notional amortisation period. Refinancing while being exposed to
merchant REC prices is likely to be difficult.
Given all of these impacts caused as a result of the sovereign risk that arises from any reduction to the RET,
there is a risk for the Australian Government that the policy objective of achieving even the reduced targets
might not be met.
This risk of not meeting the policy goal is greatest with a rolling target. As acknowledged by the RET Review
Report, this scenario in which targets are not fixed on a forward basis "would result in a degree of uncertainty
for the renewable energy industry and labile entities, and there is a risk it may not provide sufficient notice to
meet targets, given the lead time required to build new large-scale projects."9
9 RET Review Report, page 50.
Impact of sovereign and legal
risks on financing and
A critical consideration (apparently) not
considered by the Expert Panel is the adverse
impact that various sovereign and regulatory risks
are likely to have on existing and future financing
and off-take contracting arrangements. All of the
risks and impact outlined above in section 2 will
manifest as review and other trigger events under
debt facility agreements and PPAs,10 and which
could lead to a range of adverse contractual
outcomes that impact on the financial viability of
existing and new projects.
10 These risks and impacts could also have an adverse impact on
property, construction and other third-party contracts that have been
put in place in relation to existing projects or those under development.
It is beyond the scope of this report to consider all of these potential
contractual implications, suffice to say that they are likely to arise in any
legal challenges for compensation in relation to sunk costs and other
losses of project developers and investors.
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Under a typical long-term PPA for a large-scale renewable energy project in the Australian market, the
renewable energy generator enters into a forward agreement with an electricity retailer (or other liable entity)
under which the retailer agrees to purchase all electricity generated (under a contract for difference against
the wholesale pool price for electricity and the agreed notional forward price for electricity) and all RECs
generated (for a fixed forward price usually adjusted for CPI).
In considering the impact of various sovereign risks on these PPAs, there are two key commercial
considerations for the renewable energy generator and retailers:
allocation of change of law risk between the parties; and
change in control provisions.
The tenor of a typical "bundled" PPA is anywhere from 10 to 20 years, with most PPAs in the Australian
market in the last three to four years being 15 years. For the purposes of this report, we have allocated offtake
agreements that have been entered into to date into two categories:11
1. No change in law risk for project sponsor
Many of the PPAs entered into for large-scale renewable energy projects in the past six years were
generally done on the basis that the electricity retailer took all change in law risk in relation to repeal or
amendments to the RET. The tenor of these older PPAs is generally longer (e.g. 15 to 20 years) than
more recent PPAs (reflecting the level of risk that retailers attribute to the RET). In a typical change in
law provision found in such PPAs, it explicitly provides for the retailer remaining labile to pay for RECs
even if the project is unable to create and/or deliver RECs due to a change in law:
"If a Change in Law prevents Party A being entitled to create RECs or otherwise comply
with its obligations under the Agreement in relation to the creation of RECs (including by
preventing Party A from being a 'Registered Person' and/or the 'Facility' from being an
'Accredited Plant', as defined in the REC Act), then the Agreement will not be regarded
as frustrated and neither Party A nor Party B has any right to terminate the Agreement,
nor to adjust the Fixed Price under this Confirmation for the RECs (which will remain
payable despite the Change in Law and the cessation of delivery of RECs to Party B)."
2. Shared change in law risk between retailer and project sponsor
These PPAs tend to have shorter tenors than the initial off-take agreements, typically between 10 and
15 years, with some sharing of the change in law risk by the project sponsor. The risk can be shared in
a number of different ways, but the two most common options to date include:
2.1 Setting an agreed price floor that will apply in the event that:
"a Change in Law prevents the Seller from being entitled to create any Environmental Products
or otherwise comply with its obligations under the [off-take agreement] with respect to
11 For the purposes of this report, we have not included the 'wrapped' PPAs that have typically been offered by AGL under which AGL
as offtaker takes all change in law risk for the life of the project and as operator, runs and operates the project.
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Environmental Products ( including where the Environmental Products are LGCs, the Seller
from being a 'Registered Person' and/or the Project from being an "Accredited Plant" as defined
under the REC Act".
Under this option, the price floor is often set below the price the project would have received for
RECs. The "discount" on the price floor effectively transfers a portion of the change in law risk
to the sponsor.
2.2 An initial off-take period (e.g. 10 years) with an option to extend for a further period (e.g. five
years). During the initial period, the retailer bears the change in law risk in relation to the repeal
or amendment of the RET. Exercise of the option for a further period may be made conditional
on the continued existence of the RET scheme (i.e. effectively shifting the change of law risk on
the project in relation to the option) or, alternatively, the option period may have a discounted
pricing arrangement which applies in the event of a change in law as per 2.1 above.
It is evident that projects operating under no change in law risk PPAs will be shielded from the direct
impact of any amendments to the large-scale RET. However, the impact on PPAs is not the direct
impact of any change in law, but the indirect impact as these PPAs expire, where it is expected that
retailers will be less willing to agree to further PPA arrangements and projects will invariably have to
operate on a merchant basis with lower REC prices.
Projects operating under shared change in law risk PPAs will also not be directly affected; the risk sharing
mechanisms (such as the discounted price floor) have typically been structured to ensure that projects can
continue to operate, albeit on a less profitable basis (i.e. the floor price might have been set just above a
lower (but acceptable) rate of return for the project).
For new projects that are able to secure a long-term PPA of, for example, 5 to 10 years under a fixed "real"
20% target - despite the likely difficulties of this as outlined above - it is likely that electricity retailers will require
more risk sharing from project sponsors - either with options over further terms contingent on further RET
changes or REC market prices.
The most significant risk of any reduction to the RET will manifest itself in the financing agreements of
existing and future projects.
Most debt facilities for Australian renewable energy projects typically have tenors of between three and
seven years (excluding for the construction period), which implies that most existing renewable energy
projects established on a project financed basis will be due for refinancing over the period 2016
Given that most PPAs in the market are for 15 years the immediate repayment risk to lenders is not
significantly worse under any particular reduction scenario. However, when refinancing, debt financiers will
update their assumptions on risk, including the level of merchant price risk that the project will face during
the uncontracted tail of the project. As outlined in section 2 above, the financing risk posed for projects
operating in an uncontracted period is likely to increase as the term of existing PPAs move closer to expiry.
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In general, debt financing agreements contain a cascading set of review and default mechanisms which will
be triggered with any reduction to the RET. These are designed to protect the interests of the lenders. In a
worst case scenario, these review and debt resizing mechanisms could lead to actual default, which
if not remedied through further restructuring or increased capital contributions from equity, will
result in an enforcement scenario.
Review mechanisms which are likely to be triggered with any reduction to the RET include review events
and a potential cash sweep by the lenders are discussed in further detail below.
The most immediate and likely consequence of any amendments to the RET will be the triggering of a
"review event" under existing financial agreements which will allow lenders to update their assumptions and
projections for future revenue.
A change in the RET Act is often explicitly listed as a "review event" in financing agreements, given the
potential impact changes to the RET will have on a project's revenue stream. If it is not explicitly provided
for, a RET reduction scenario would likely fall within the typical catchall provision of "any event that may
have a material and adverse impact" on a project.
Given RECs account for generally around half of a project's revenue stream, there is little doubt that
a review event would be triggered by a reduction to the RET for most project-financed renewable
projects in Australia. The review mechanisms are generally quite prescriptive to ensure close adherence.
An example of a typical review mechanism is set out below:
If a Change in the Renewable Energy Law occurs which is reasonably likely to have a material
adverse effect on the Borrower, the Borrower must prepare and submit to the Agent a revised Base
Case Model with respect to the Project to take into account the economic effect of the change or
repeal to the RET.
If the revised Base Case Model demonstrates that any of the Debt Sizing Parameters are no longer
satisfied, then the revised Base Case Model will be used to determine:
a revised Facility Limit which will result in each of Debt Sizing Parameters being satisfied; and
a revised Amortisation Schedule.
Until the Principal Outstanding under the Facility is reduced to the revised Facility Limit, all distributable
cash must be applied towards prepayment of the principal outstanding (i.e. cash sweep).
It is important to note that the lenders often have considerable scope in determining what assumptions are
included in the revised forecast. This means that the assumptions and forecasts used for the Base Case
Model cannot be unrealistic. On the contrary, given the regulatory uncertainty that will persist under
any of the scenarios, lenders are likely to take very conservative stance on any assumptions and
Any reduction to the RET will almost certainly trigger review events under existing financial arrangements.
The key difference will be the magnitude of the adjustments and the duration of cash sweep as each
particular scenario considered in the RET Review Report will affect the base case model differently.
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If, based on the revised forecasts, a project is unable to satisfy the key financial ratios, a cash sweep
will likely be triggered. A cash sweep is a mandatory prepayment of the loans from all or a defined
percentage of surplus cash flow. Lenders will continually project whether or not their required cover ratios
could be met by the projects, even if the refinancing did not take place. To the extent that the projects show
that ratios could not be met the loan will be prepaid out of surplus cash flow to ensure that the ratios can be
met in the future. A cash sweep effectively suspends the equity owners and investors from receiving
any return on their capital (i.e. prepay the loan rather than pay out dividends), which puts increased
financial pressure on equity.
A reduction to the RET may see cash sweeps by lenders persisting for a significant period, putting
increased financial pressure on equity. The key factor will be equity's resilience and ability to endure any
freeze on distributions. This places considerable pressure on equity which may be forced to try sell a
distressed asset in a weak market setting or walk away from the project (potentially leaving banks stranded
with the project).
For merchant projects, cash sweeps are often forward looking. That is, projections of the ability to meet
cover ratios in the future. If merchant prices are projected to fall, a cash sweep will commence to provide a
buffer for when revenues (and ability to service the loan) are diminished.
For existing operators, the financing risk will arise when trying to refinance existing loans. Two factors are
likely to impact on the ability of existing projects to obtain refinancing:
1. Australian and foreign banks are likely to be reluctant to continue to lend, given the future regulatory
uncertainty; the reduction in liquidity could further drive up refinancing costs for sponsors
(assuming refinancing can be obtained); and
2. Debt sizing parameters could be tightened as banks adopt more constrictive merchant pricing
assumptions and factor in the increased REC price uncertainty.
The key factor that determines the size of the loan is derived from the projects ability to service the cost of
the loan. The Debt Service Cover Ratio (DSCR) measures the net operating revenue of a project in a given
period against the cost of servicing the interest and repaying the loan principal during that period. In order to
raise project finance, the cash flows of an operator need to be predictable. The less predicable the expected
cash flow, the greater the risk of the operator not being able to meet its financial obligations. As a result,
lenders often require projects to maintain a "cash cushion.". The more certain the cash flows, the smaller the
cash cushion needs to be:
for projects with a contracted cash flow (i.e. bankable PPA), the DSCR is typically between 1.30 to
1.40 times operating revenue;
for projects without an off-take agreement, they must typically maintain a DSCR of between 1.80 to 2.10.
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Given the greater volatility of merchant energy and merchant REC prices, higher DSCRs can be
particularly onerous for merchant projects. For this reason, it is often crucial for projects to obtain an offtake
agreement in which there is clear contracted cash flow in order to be financially viable.
We note that while most renewable energy projects in Australia are financed on a non-recourse project
finance basis, many developers are relying on typical corporate financing to fund projects. Corporate
financing is typically more expensive to service than project financing and carries with it the added risk that
cash-flow issues on one project could result in the company defaulting on its loan.
Risk of default
Under the typical financing arrangements as outlined above, projects will end up in default if:
the cash sweep is insufficient to cover the debt servicing costs; or
the project is unable to refinance on economically viable terms.
Under most financing facilities, default will allow the lenders to:
declare that all or part of the secured debt is immediately due and payable;
declare that the commitments of each lender are cancelled;
draw upon any equity support instruments as permitted; or
direct a Security Trustee to enforce the security over the assets of the project.
Whether or not projects end up in default will depend on the level of financial stress and the impacts any
amendments to the RET ultimately have on their operating revenue. It will also, in part, depend on how
much stress each particular equity sponsor can withstand before a project ends up in default. The financial
capacity of existing owners to absorb increasing financial pressure through a review event, cash
sweep and ultimately default scenario varies significantly for existing renewable energy projects.
In general, projects that are reliant on merchant pricing will be far more susceptible to default than
contracted projects. That said, many projects will enter an uncontracted tail period in the next eight to
10 years which could put significant pressure on project revenues leading to sweep events and
possibly default. Again, much of this will depend on the financial capacity of the equity sponsor to increase
capital contributions and/or endure persistent cash sweeps with no equity distributions.
A lower RET may result in lenders being required to enforce their security. In such circumstances, equity
will likely take a significant write-down (even up to 100%) on the value of their investment and
lenders could be left with renewable projects as distressed assets. In this situation, lenders will likely
try and sell the project to recoup the value of the outstanding debt. However, this could be difficult given any
ongoing REC pricing uncertainty out to 2030.
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Financing impacts of a reduced RET
With a reduced RET, many large-scale renewable energy projects could be under severe financial strain as
review and cash sweep mechanisms under financing agreements are triggered, placing pressure on equity
to reduce debt sizing. The impact is likely to be most severe under a rolling "real" 20% target as the higher
merchant risk and policy uncertainty will impact on lenders' confidence in the predictability and stability of the
If projects do become stranded and default, the risk of not meeting policy goals could increase significantly.
The presumption of the Expert Panel that very few projects will become financially distressed or stranded is
unrealistically optimistic. For the range of financial and merchant price impacts described in detail in
section 2 above, this seems unlikely given the exposure uncontracted projects will have to the decrease in
merchant REC prices and the structure of existing financial arrangements.12 Moreover, a "real" 20% target
assumes that new projects will be attracted to the market, notwithstanding that some existing projects may
default and exit the market. It is unrealistic of the RET Review Report not to consider that this could occur
given the difficulty new projects will have in obtaining long term off-take agreements (i.e. contracted cash
flow) as well as debt financing.
12 Bloomberg New Energy Finance notes that there are at least seven large scale wind farms operating on an uncontracted basis.
Issues in relation to
Given the likely financial, price and other risks that
will have an adverse impact on existing operators
and project developers described in this report, it
is highly likely that the Australian Government will
face a number of legal challenges if the RET is
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Any reduction of the RET will require some form of compensation or transitional assistance in order
to achieve policy objectives, namely maintaining the financial viability of existing and new renewable
energy projects so that reduced targets are met and market participants are not unfairly treated as a result of
The Expert Panel itself acknowledges that any compensation mechanisms implemented by the Government
will need to deal with the legitimacy of compensating developers, and meet the policy objective "that the
RET continues to support projects already established under the scheme in a sustainable and orderly
However, designing and implementing compensation or transitional assistance will involve
significant inherent complexities and policy issues that could potentially undermine the overall
effectiveness and efficiency of the modified RET. This complexity challenge also applies to the price
intervention mechanisms proposed by the Expert Panel.14
Even if all of these complexities are dealt with, and a compensation regime is implemented as a result of a
modified RET, there is no guarantee that any regime will be sufficient to satisfy debt and equity financiers.
The confidence of debt financiers, in particular, will be critical to the success of any compensation or price
intervention mechanisms. But given recent ongoing uncertainty regarding the status of the RET,
implementing a compensation scheme that will be robust enough to satisfy banks and investors will be a
high hurdle to overcome.
The range of complex issues that will need to be considered include:
clarifying the legal and policy basis for any compensation;
determining the criteria for the threshold at which existing operators and new entrants will be eligible for
compensation and those that will not;
determining the criteria for calculating and verifying losses and costs against which compensation
amounts would be paid; and
agreeing on the form and timing of compensation to be paid.
Clarifying the legal and policy grounds for any compensation
A range of issues arise in considering the legal and policy basis for providing compensation:
on what grounds is compensation legally required;
on what grounds is compensation desirable in light of the impact of the various sovereign risks arising
from changes to the RET;
on what grounds are additional policy measures (such as price intervention mechanisms) required to
ensure that a modified RET continues to operate effectively and efficiently?
13 RET Review Report page 111.
14 ET Review Report, page 112.
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A further difficulty for the Government in implementing any compensation or assistance regime is the
likelihood for legal challenges which developers may bring as a result of any amendments to the RET and
any associated compensation regime. In light of the potential adverse impacts on debt and equity investors
as outlined in sections 2 and 3 above, it is highly likely that the Australian Government will face a number of
legal challenges as a result of implementing any reduction to the RET.
Grounds on which it might be expected that legal challenges will be commenced could include acquisition of
property rights on unfair terms, judicial review (in relation to compensation awards), estoppel or
misrepresentation (in respect of legitimate reliance by developers and investors on statements made by the
Government). It is, however, beyond the scope of this report to provide a detailed analysis of these legal
grounds, although there are certainly examples of litigation in other jurisdictions.15
Irrespective of the likelihood of any legal challenge succeeding, the Government will still need to carefully
consider appropriate mechanisms to compensate for:
the financing and refinancing risks faced by existing operators and any new entrants;
sunk costs incurred by project developers who are prevented from entering the market because of
reduced REC demand and the need for less new capacity to be built.
Even if there was no prospect of legal challenges being brought against the Government - or if they had little
prospect of success - the Government would still need to ensure any reduced RET can continue to operate
effectively and efficiently. As explained in sections 2 and 3 above, there is a real risk that there will not be
sufficient liquidity in the market for long-term price discovery based on a reasonably certain forecasting of
the balance of supply and demand of RECs so as to ensure the orderly build-out of additional renewable
generation capacity to meet even the reduced targets. Complex compensation and other transitional
measures are going to be required regardless to ensure sufficient continuity in the RET market.
15 In overseas jurisdictions where government reform to renewable energy regulation has been enacted or foreshadowed, there has
been significant discussion and developments regarding legal challenges in relation to the lawfulness of retrospective reforms. In
the UK in 2012 it was concluded that announced retrospective changes to Feed-in-Tariffs that brought forward the cut-off date for
payments were unlawful. There was no power under the relevant statute to make delegated legislation retrospective. Following this
decision, the UK Government had to change its proposed reforms: Friends of the Earth v Department of Energy and Climate
Change  EWCA Civ. 28;  ENV L.R. 25. In July 2014, the High Court of England and Wales ruled in favour of solar
companies seeking damages in relation to the proposed unlawful reforms, even though these were never legislated: Breyer Group
plc and others v Department of Energy and Climate Change  All ER (D) 106 (Jul);  EWHC 2257 (QB). The companies
successfully argued that, by the time the Court ruled that the proposed reforms were unlawful, the damage was done. The projects
that would otherwise have been completed prior to reforms had been abandoned because of the clear statements made by the UK
Government that the cut-off date was being moved forward. Spain has retrospectively reduced feed-in-tariffs for renewable energy
projects and Italy is in the process of introducing retrospective changes. Legal action has been foreshadowed with respect to the
adverse impact of these changes. These legal challenges may be indicative of some of the potential legal issues that the Australian
Government could face following changes to the RET.
Legal action has also been commenced under international law. Following the retrospective reduction of the feed-in-tariff in Spain,
there are several arbitration cases pending between investors in renewable energy projects and the Spanish Government under the
Energy Charter Treaty. The Energy Charter Treaty includes provisions that are aimed at promoting and protecting cross-border
investments between countries in energy infrastructure.
www.bakermckenzie.com CEC report | 21
Determining threshold for compensation
One of the difficulties the Government will have to contend with when designing any compensation regime is
determining where to draw the line under project developers entitled to compensation.
While the guiding principle for the Government in this regard would be relatively simple - what is fair in the
circumstances - the implementation of this principle of fairness will be highly complex because those
circumstances will vary significantly from project to project, developer to developer, lender to lender.
Key issues likely to arise include:
at which point will projects not yet operating be grandfathered into a reduced RET?
at which point is the threshold drawn for compensating those projects that will not be able to participate
under the modified RET? How far down the project pipeline does a developer need to be in order to be
eligible for compensation?
how will a compensation regime allow for the delay in seeing how the market plays out and when it
becomes apparent in a few years time which projects have been successful in being developed under the
lower RET target?
how will the Government determine which projects do not proceed because of the reduced RET and
which do not proceed due to other reasons?
if upfront compensation is provided, will further compensation be provided if the full extent of any loss is
only evident or manifests itself much later on?
is it possible or efficient to have a single set of criteria for calculating levels of compensation for all
how can the compensation arrangements account for the specific financial arrangements and other
equity and contracting circumstances of each renewable energy project?
how are the claimed losses and costs of operators and developers adequately quantified and verified?
The complexity of compensation is highlighted in the RET Review Report in relation to where to draw the
line for Scenario 1: Closed to new entrants target. The Expert Panel recommended that eligibility extend to
projects already under construction, and those projects to be constructed where "project proponents can
demonstrate that there is full financial and contractual commitment to the project (e.g. final investment
decision, engineering and procurement contract) within one month of the announcement of this approach."16
While this sounds relatively straightforward on the face of it, the Government would still need to come up
with a fair and objective framework for determining whether projects have reached a final investment
decision. Would this need to be linked to binding financial commitment from debt financiers, or would a final
investment decision of the equity sponsors be sufficient? Moreover, the Government will need to make
some complex decisions as to whether, and to what degree, it will compensate:
those developers that meet eligibility requirements but whose projects are no longer viable under a
reduced RET; and
16 RET Review Report, page 64.
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how far it will extend compensation beyond those developers with full financial and contractual
commitment, to compensate for sunk costs incurred by developers no longer able to enter the market.
There are a significant number of renewable energy developers currently progressing greenfield projects in
Australia that have incurred substantial sunk costs to date and - with a reduced RET - would not be able to
enter the market. The RET Review Report includes information on the planning and development of largescale
renewable energy projects and their status in 2014 from analysis by the Clean Energy Regulator,
which shows a significant number of projects that have not yet achieved financial close but are likely to have
already resulted in significant costs which would be sunk if they could no longer participate in the market.17
While the RET market is a competitive market where projects compete between each other and
technologies to sell RECs (particularly in relation to securing a long-term PPA for bankable revenue), it is
clear that many of the projects currently in the development pipeline will not be able to enter the market with
a lower RET.
Whatever criteria are ultimately settled upon to determine where to draw this line, there is likely to be a
significant number of renewable energy developers claiming entitlement to some form of compensation.
Form and timing of compensation
The Government will need to consider the mechanics of how compensation and assistance is paid
out - each with their own complexities - as well as the timing over which compensation might be paid or price
intervention mechanisms are introduced. We examine below three possible mechanisms as to form and
timing of compensation, including the price intervention mechanisms proposed by the Expert Panel.
Price intervention mechanisms
The Expert Panel acknowledges that following any RET reduction, various factors "may drive significant
price volatility in the spot market for LGCs" and various options to support the price are proposed.18
However, all of the proposed options involve price intervention measures to tweak supply and demand in the
market to achieve a particular price or price range. However, based on what is included in the RET Review
Report on these mechanisms, it seems unlikely that any of these options would be able to adequately deal
with the range of financing, price and other contractual risks as outlined in this report.
Under any price intervention mechanism, a reference price would need to be determined. But this raises a
number of issues:
what is the basis for determining any reference price? Which modelling would this be based on (which
even the Expert Panel recognises has its limitations given the significant differences in pricing that
different models have produced)?
if rolling annual targets are set, there will be a level of arbitrariness to any reference price given the
difficulty in modelling supply and demand;
17 RET Review Report, page 33.
18 RET Review Report pages 111-112.
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for investors and lenders to have confidence in the price set by the Government, they will need to be
consulted during the process of determining price, but how realistic is it to determine a reference price by
way of stakeholder consultation?
The options of a fixed price and setting a price cap and floor are likely to be economically inefficient on the
for either option to maintain project viability, the fixed price or price floor would need to be set for the
most expensive project in the market, resulting in an inefficient outcome as some developers may make
windfall gains; conversely, if the fixed price or price floor is not set for the most expensive project, but is
set lower, some developers could still experience losses;
actual costs of developers will need to be obtained to determine an appropriate fixed price or price floor.
This will require all of the developers submitting their costs to the Government, and the Government
assessing and verifying this information. The administrative costs associated with obtaining and verifying
this information could be substantial.
Lump sum payments
Any lump sum payment would need to quantify the loss of market value of RECs, based upon what the price
would have been had the RET remained unchanged. The Government would need to determine what this price
would have been which would be informed by modelling work as for the reference price described above.
The Government would need to decide whether a lump sum payment is based on average costs for the
market as a whole, or based on actual individual costs and losses for each individual project. In both cases,
the Government would need to consider and verify a significant amount of data on developers' costs to try to
ensure that any compensation amounts paid out do adequately compensate for the loss incurred.
Any lump sum payment mechanism would need to consider a number of issues:
the Government would need to set the payment(s) to avoid windfall gains and/or significant losses;
in calculating developers' costs, the Government would need to decide whether these will be based upon
real costs of individuals, such as termination of contracts, or whether it would determine a benchmark for
the market to account for variability in negotiations of contracts;
the Government would need to decide whether it will appoint a third party auditor or valuer for each project;
the Government would need to decide whether payments to existing operators will compensate them up
to the end of their existing PPAs or beyond this for the uncontracted period which is likely to have a lower
the Government would need to decide whether payments would be different for existing operators and
any new entrants; and
the Government would need to determine whether there would be any obligations for developers to pay
back where REC prices in the long run exceed compensation forecasts.
Given the number of developers involved and the varying circumstances of each that would need to be
factored in, determining lump sum payments would be complex and administratively burdensome.
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Contracts for Difference
Another mechanism could be contracts for difference (CfDs) rather than lump sum payments. CfDs would
pay out the difference between the developers' base case financial model at financial close or at some other
point determined by the Government, and the reference price set by the Government, potentially the
average market price depending on what price support mechanisms are put in place that do sustain REC
prices, or a price based on modelling of prices under the existing RET. Given that there will be a range of
different capital costs, equity return expectations and debt costs that go into each project's financial model,
the Government would need to determine whether it comes up with an average cost base against with
compensation payments are made, or individual in respect of each project.
CfDs would need to be long term and legally robust to provide sufficient certainty to investors and debt
financiers as projects are financed and refinanced.
Issues the Government would need to deal with on any potential CfD mechanism include the following.
What would the term of the CfDs be? Would the term differ depending on the developer's circumstances,
and if so, how would different terms be decided?
Would payments be conditional on developers continuing operations? Would developers be required to
pay an amount back to the Government if they ceased operating?
What would the termination conditions be? How could they be drafted in such a way as to provide the
requisite certainty for shareholders and banks?
How would the CfDs account for the different financing and equity costs of each project? And in such a
way to avoid windfall gains and no ongoing losses that affect the viability of existing projects?
Partner, Baker & McKenzie
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