From the
editor’s desk…
Welcome
to Pipes & Wires #164. This issue starts with a summary of the long-term
lease of Endeavour Energy by the NSW government, and then continues the theme
of who pays to integrate distributed generation in the context of a California
rate case.
We
then consider a couple of electricity wires and gas pipes regulatory decisions
in Australia and New Zealand, and then examine some security of supply and
energy mix issues in Australia and the United States. This issue then closes
with a quick look at some nuclear issues in Lithuania and South Africa.
So …
until next month, happy reading…
What’s trending ??
Some of
the industry themes and trends that are emerging include…
· Establishment of committees and task forces to inquire into security
of electricity supply.
· Regulators using merger approval processes to force electric
companies to implement wider objectives such as public policy goals.
· Development of national strategies for various things (like
closing thermal power stations) that a few years ago would have been
“market-led”.
· What appears to be some confusion amongst regulators about
to how to regulate emerging technologies such as batteries and solar. Given
that these technologies seem to be giving customers increased choice about
where they obtain their electricity from, perhaps the question should be
whether to regulate.
· A rapidly increasing awareness of the importance of thermal
generation for renewable buffering, both in the context of moment-by-moment
fluctuations in wind and solar, but also in the traditionally understood sense
of dry hydro years.
· A sense that some governments may be losing patience with
the slow pace of the transition to renewables, and the heightened possibility
that those governments may move from encouraging through incentives to
mandating through sanctions.
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Mergers & asset sales
Aus – the long-term lease of Endeavour Energy
Introduction
The
winning bidder for the long-term lease of a 50.4% stake in Endeavour Energy was announced in mid-May. This article examines that bid
and makes some brief comparisons with the other two long-term leases (Transgrid
and Ausgrid).
A bit about Endeavour Energy
Endeavour Energy is the poles & wires business that supplies 934,000
customers across 24,800 km2 of Illawarra, the South Coast, the
Southern Highlands, the Blue Mountains and Sydney’s south-west and western
suburbs. Key financials are approximately…
· Annual revenue is about $1.6b
· EBITDA of $795m.
· NOPAT of $244m.
· ROR of 13.7%.
The winning bid for Endeavour Energy
The
winning bid of $7.624b was from the Advance Energy consortium led by Macquarie Bank and including AMP Capital, the British Columbia Investment Management Corporation and the Qatar Investment Authority. This is above the $7.2b forecast lease price based on the
9.1x EBITDA multiple achieved by the Ausgrid lease.
The
nett proceeds of the lease after costs and debt repayment were $2.9b.
Comparisons with the Transgrid and Ausgrid leases
Key
features of the three leases are as follows…
|
Parameter |
Endeavour
Energy |
||
|
Winner |
Hastings
Funds Management et al. |
IFM
Investors et al. |
Macquarie
Bank et al. |
|
Bid |
$10.258b |
$16.1b |
$7.624b |
Proceeds of the overall lease process
The
three leases have raised $23b (nett), which is over $2b more than the $20b
target. Sales proceeds will be applied to a range of projects, including the WestConnex motorway and Metro rail line project.
Tariffs, subsidies & tax credits
US – who pays to integrate DER’s ?
Introduction
Who
pays to integrate distributed energy resources (DER’s) into the distribution
network seems to be one of those prickly questions for which the discussion
seems ideological even though the answer is analytical. This article unpicks
that issue using Southern California Edison’s (SoCalEd) recent Rate Case as a starting point.
The SoCalEd Rate Case
SoCalEd
recently submitted its Rate Case to the Public Utilities Commission which seeks approval to spend inter alia $2.1b to ready its distribution network for a further
1,500,000 DER’s by 2025. This $2.1b is proposed to improve the following 4
features of the network (and is not simply to replace aging assets)…
· Structural upgrading, including replacement of the
inadequate 4kV circuits.
· Automation for real-time monitoring and control. This
includes accommodating two-way power flows as required by the PUC’s Distribution Resources Plan.
· New communications capabilities including optical fiber and
Wi-Fi.
· New system management software.
The ideological angles
The
crunchy issue doesn’t seem to be so much about whether SoCalEd should spend
the $2.1b, but rather whether it should be allowed to recover that $2.1b
spend through its regulated rates (tariffs). There are obviously a range of
ideological angles on this proposed spend…
· SoCalEd (and presumably other electric companies) simply
want to prepare their networks for an expected increase in DER’s. Arguably,
they should be perfectly entitled to recover the efficient cost of implementing
a regulatory obligation.
· The DER industry (of which the roof-top solar lobby seems to
be the most visible and vocal) claim that SoCalEd is not properly valuing DER’s
in its planning and that SoCalEd is further claiming that DER’s impose costs
rather than benefits (refer to Pipes & Wires #137 and #157). A further strand of their argument is that at least some
of network improvements (like communications and automation) could be provided
by third parties including DER’s through competitive tenders.
· To add a third angle to this, customer advocacy group The Utility Reform
Network (TURN) claim that neither SoCalEd nor the DER’s arguments
are supported by facts and instead claim that SoCalEd is simply using DER’s to
justify gold-plating its network. A particular aspect of TURN’s concern is the
claim that third-party DER will reduce the need for network improvements (and a
little thought would support this concern).
Pipes
& Wires will continue its analysis of who pays for DER integration as this
progresses.
Network access decisions
NZ – gas under pressure
Introduction
The Commerce
Commission recently released its cost of capital decision that will apply to all gas distribution and transmission default price
paths (DPP’s) for the period starting on 1st October 2017. This
article examines the key features of that determination.
Regulatory frameworks
The regulatory
frameworks for setting the WACC are set out in clauses 4.4.1 to 4.4.10 of the Gas Distribution Services Input Methodologies Determination 2012 and the Gas Transmission Services Input Methodologies 2012 respectively. Those determinations are made pursuant to Part 4 of the Commerce Act 1986.
Key features of the WACC’s
Key features of
the WACC’s include…
|
Parameter |
Mid-point |
67th
percentile |
|
Vanilla WACC |
5.95% |
6.41% |
|
Post-tax WACC |
Not stated |
5.85% |
Aus – the final
Tasmanian electricity distribution determination
Introduction
The Australian Energy Regulator (AER)
recently released its’ Final
Decision for TasNetworks
distribution business for the two year period from 1st July 2017 to
30th June 2019. This article examines the key features of that
Decision.
The reason
for a two year Decision
The Tasmanian government amalgamated its
transmission grid Transend with the distribution business of Aurora Energy on 1st
July 2014 (refer to Pipes
& Wires #113). This two year
regulatory period is to align the regulatory periods for TasNetworks
transmission and distribution businesses. TasNetworks distribution will be
subject to a 5 year Decision commencing on 1st July 2019.
Regulatory
framework
The regulatory framework is based on the National
Electricity (South Australia) Act 1996, which
provides for the making of the National Electricity
Rules (version 79 at the
time of writing). Electricity distribution determinations are principally made
pursuant to Chapter 6
of the Rules.
The
determination process to date
The determination process to date includes
the following…
|
Parameter |
Proposal |
Draft determination |
Revised proposal |
Final determination |
|
CapEx |
$213.4m |
$213.4m |
$223.2m |
$213.4m |
|
OpEx |
$123.1m |
$127.6m |
$129.7m |
$136.7m |
|
Opening RAB |
$1,646.7m |
$1,629.4m |
$1,621.2m |
$1,615.2m |
|
WACC |
6.04% |
5.48% |
5.48% |
6.02% |
|
Regulatory depreciation |
$107.2m |
$98.6m |
$96.2m |
$95.8m |
|
Total smoothed revenue |
$493.3m |
$446.6m |
$458.2m |
$477.3m |
This concludes Pipes & Wires of the Tasmanian
electricity distribution.
NZ – Powerco applies for a Customised Price Path (CPP)
Introduction
Powerco recently applied for a Customised Price-Quality Path (CPP) for its electricity distribution business. This
article examines what a CPP is, why a company might apply for a CPP, and the
key features of Powerco’s CPP application.
Background to the CPP
Powerco
is one of 17 electricity distribution businesses that is subject to Default
Price-Quality Path regulation under Part 4 of the Commerce Act 1986. Readers should be broadly familiar with the DPP’s concepts
and processes from Pipes & Wires articles, and understand that New Zealand
doesn’t use the “propose - respond” model common in other jurisdictions.
Subpart 6 of Part 4 provides the opportunity for individual regulated
businesses to seek an alternative price-quality path that better meets its
particular circumstances. That alternative is the CPP which is the equivalent
of the Rate Case or Regulatory Proposal and effectively uses a “propose –
respond” model.
So in
broad terms, a CPP would seek approval for 1 or both of the following…
· To operate at a different point on the same
existing price-reliability curve. This might be in response to customer
preferences for paying less to have less reliability (ie. more or longer
outages).
· To adopt a different price-reliability curve. This might be
because the required reliability cannot be sustainably achieved at the
allowable price (revenue).
Key features of Powerco’s CPP proposal
Key
features of Powerco’s CPP proposal include…
· CapEx of $873m, which represents a 50% increase viz-a-viz
the previous 5 years, including $286m in growth and security of supply
projects.
· OpEx of $455m, which represents a 28% increase viz-a-viz the
previous 5 years, including $289m on network OpEx (which represents a 38%
increase viz-a-viz the previous 5 years) and $165m of non-network OpEx.
· SAIDI of 195.9 and a SAIFI of 2.31.
· Return on investment of $788.5m.
· Depreciation of $296.6m
· Pre-smoothed (building block) revenue of $1,241.3m
Next steps
The
Commerce Commission will now assess Powerco’s application. Pipes & Wires
will provide further analysis once their decisions are released.
Aus – the Court judgement on electricity revenue determinations
Introduction
Australia’s
Full Federal Court recently released its judgement on the Australian Energy
Regulator’s (AER) appeal of the Australian
Competition Tribunal’s findings in regard to several electricity revenue
determinations. This brief article examines the sequence of events, the Court’s
decision around the OpEx and Gamma aspects of the determinations, and the
likely implications.
Sequence of events
The
sequence of events is as follows…
· In April 2015 the AER determined the allowed revenues for the electricity distributors in NSW and the ACT
(Ausgrid, Endeavour Energy, Essential Energy and ActewAGL).
· In June 2015 the 4 electricity distributors applied to the Tribunal for a review of the AER’s determinations on the basis that the AER had made material errors in its
determinations. The legal framework for appealing that determination is set out
in s71B of the National Electricity Law.
· In February 2016 the Tribunal ruled in favor of the 4 electricity distributors in regard to inter alia OpEx, but also rules in favor
of the AER on several aspects. The Tribunal instructed the AER to inter
alia re-determine various aspects of the original determinations.
· The AER appealed the Tribunal’s ruling to the Federal Court
on the basis that the Tribunal had made a legally incorrect decision.
· The Court judgement upheld some of the Tribunal’s findings (in
favor of the electric companies) whilst also finding errors and shortcomings in
some aspects of the Tribunal’s ruling (in favor of the AER).
The Court’s ruling
The
Court ruled inter alia…
· That the AER has not established any of the grounds of
judicial review in relation to the OpEx forecasts (Para 386). This means that
the Tribunal’s decision to set aside the AER’s original OpEx allowances is
upheld.
· That the Tribunal misunderstood the function of imputation
credits (Para 751). This means that the AER’s approach to Gamma was not a
reviewable error (Para 756).
It is
important to also broadly note the following…
· Neither the Court nor the Tribunal are “making” or
“re-making” any part of the revenue determination. That task remains with the
AER.
· The Court judgement and the Tribunal ruling do not require
the AER to allow higher revenues per se.
They simply require the AER to adhere to the revenue setting process set out in
the National Electricity Rules.
The likely implications
The
likely implications of the Court’s judgement are inter alia…
· A re-thinking of how OpEx benchmarking and various
efficiency principles are practically applied.
· Higher electricity distribution charges in NSW and the ACT as
a result of the AER amending the original determinations.
· Flow-on implications for the revenue determinations in other
states.
· Renewed efforts to abolish the limited merits review process.
NZ – gas under more pressure
Introduction
Pipes & Wires #161 and #163 examined the Draft Default Price-Quality Paths (DPP’s)
compiled by the Commerce Commission that will apply to…
· the gas distribution businesses owned by GasNet, Powerco, Vector and First Gas.
· all gas transmission businesses.
This
article examines the Final DPP’s that were released by the Commission last month, and which
will apply from 1st October 2017.
Regulatory framework
The
regulatory frameworks are drawn from Part 4 of the Commerce Act 1986. Subpart 10 addresses gas pipeline services, and in particular subjects
all gas pipeline services to price-quality regulation (s55D).
Key features of the Distribution Final DPP
Key
features of the Distribution Final DPP (compared to the Draft) include…
|
Feature |
Draft |
Final |
|
Provision
for submitting a CPP application. |
Provision
for submitting a customised price path (CPP) application any time before 1st
October 2021 (ie the start of Year 5). |
Provision
for submitting a customised price path (CPP) application any time before 1st
October 2021 (ie the start of Year 5). |
|
Starting
prices |
Starting
prices are specified as maximum allowable revenue (MAR), and will be
specified in the final decision. |
· GasNet $4.15m · Powerco $47.31m · Vector $43.92m · First Gas $22.14m |
|
Rate
of change |
|
The
annual rate of change is 0%. |
|
Emergency
response time |
No
more than 20% of response to emergencies (RTE’s) can take more than 60
minutes, with the added requirement that the RTE to any 1 emergency cannot
exceed 180 minutes. |
No
more than 20% of response to emergencies (RTE’s) can take more than 60
minutes, with the added requirement that the RTE to any 1 emergency cannot
exceed 180 minutes. |
Key features of the Transmission DPP
Key
features of the Transmission Final DPP (compared to the Draft) include…
|
Feature |
Draft |
Final |
|
Provision
for submitting a CPP application. |
Provision
for submitting a customised price path (CPP) application any time before 1st
October 2021 (ie the start of Year 5). |
Provision
for submitting a customised price path (CPP) application any time before 1st
October 2021 (ie the start of Year 5). |
|
Starting
price (MAR) |
|
Specified
as an MAR of $121.6m. |
|
Rate
of change |
Allowable
rate of change will be 0%. |
Allowable
rate of change will be 0%. |
|
Revenue
forecasts |
|
Year
ending 30th September 2018 $121.6m. Year
ending 30th September 2019 $123.9m. Year
ending 30th September 2020 $126.4m. Year
ending 30th September 2021 $129.0m. Year
ending 30th September 2022 $131.6m. |
|
Emergency
response time |
No
RTE may exceed 180 minutes, neither can there be a major interruption. |
No
RTE may exceed 180 minutes, neither can there be a major interruption. |
|
WACC |
WACC
of 5.67% |
Mid-point
vanilla WACC of 5.95%. |
This
article concludes Pipes & Wires coverage of the gas pipeline DPP re-set.
System security & energy mix
Aus – the future of
coal-fired generation
Introduction
In
amongst a wider article on the closure of Hazelwood Power Station, Pipes & Wires #159 noted the key recommendations of the Senate Standing Committees on Environment and Communications
interim report on the retirement of coal-fired power stations. This article notes the recommendations of the final report that was presented back in late March.
Key recommendations of the
final report
The final
report recommends the following…
· Development of a comprehensive energy transition plan,
including reform of the National Electricity Market rules.
· Develop a mechanism for the orderly retirement of coal-fired
stations for consideration by the COAG Energy Council.
· Insertion of a pollution reduction objective into the
National Electricity Objectives.
· Establishment of an energy transition authority.
· That a comprehensive and independent assessment of the
health effects of coal-fired power stations be commissioned.
· That a load-based licensing arrangement based on the NSW
Scheme be developed, with fees reflecting externalities including health
impacts.
· That additional measures be taken to ensure compliance with
the standards in the National Environmental Protection (Air Quality) Measure.
· That a more rigorous assessment of emissions be provided.
· A national audit of likely mine and station rehabilitation
costs be undertaken.
· That a common national approach to setting rehabilitation
bonds be developed.
· That grid level battery storage be supported at a government
level, to promote decentralized generation whilst also enhancing grid
stability.
· That a commitment to not funding, subsidising or supporting
construction of new coal-fired generation be made.
Alignment with the interim
report
These
recommendations are consistent with the interim report, with the first 4
recommendations being pretty much identical.
Editors’ note
The
interim report noted that energy security is a number one priority, however
Pipes & Wires #159 concluded that it was not clear how that priority was
reflected in the interim recommendations. The final report also mentions
security, including a comment from the dissenting senators that energy security
must be the Governments’ number one priority. Again, it is not clear how making
security of supply a priority is reflected in those recommendations.
US – reviewing the Clean Power Plan
Introduction
Back in late March
President Trump instructed the Environmental Protection Agency (EPA) to review inter alia the Clean Power Plan (CPP). This article
takes a quick look at the CPP and the Executive Order ordering the review.
Key features of the CPP
The CPP was one of
President Obama’s flagship policies, and embodied multiple objectives of
reducing CO2 emissions, lowering energy costs and improving air
quality.
The regulatory framework
for the CPP is based on s111 of the Clean Air Act (Title 42 of the United
States Code, Section 7411) which authorises the EPA to issue nationally
applicable New Source Performance Standards which limit air pollution. Section
7411 has long been used to limit emissions of SOx, NOx
and particulates from coal-fired generation but in 2015 the EPA used this
Section to also set CO2 emission
limits.
The Executive Order
The Executive Order instructing inter alia the EPA to review the Clean
Power Plan includes the following features…
· A policy statement that
it is in the national interest to develop the US’s energy resources whilst
reducing regulatory burdens and promoting energy independence.
· Specific recognition of
both fossil fuels and renewables as an essential part of that energy mix.
· All agencies that
potentially burden the safe and efficient production of domestic energy are to
review their actions and report to the Office of Management and Budget (OMB)
within 45 days on how they will comply with the Order. The head of any agency
who doesn’t believe that their agency burdens that efficient production of
domestic energy must report to the OMB on why they believe that to be the case.
Consistency with Trump’s policy positions
How does this review of
the CPP (which ostensibly amounts to a restoration of a wider and more balanced
energy mix) stack up against President Trump’s policy positions. Pipes & Wires #161 provides a handy list of
those policy positions…
· An expected use
of coal and shale gas to benefit American families and to support American
jobs.
· Strong support
for the coal industry.
· Support for
natural gas.
· A rejection of
the principles of green energy, including the view that man-made CO2
emissions are causing global warming.
· To strengthen
America’s energy independence as a key strategic and foreign policy goal.
What will this mean for coal-fired generation ?
It would appear that
coal-fired generation may now continue into the future, presumably allowing
end-of-life asset issues and market costs to determine closures rather than CO2
emission limits.
Nuclear strategy & operations
Lithuania – decommissioning the RBMK reactors
Introduction
The Ignalina Power
Station in Lithuania is currently decommissioning its 2 RBMK
reactors. This article briefly examines that decommissioning and then considers
the forecast spike in decommissioning over the next 10 to 15 years.
A bit about Ignalina
Ignalina
is a 2 x 1,500 MW nuclear station situated in eastern Lithuania near the
Belarus border. After 4 years of preparatory work construction began in 1978.
Unit 1 was commissioned in December 1983 followed by Unit 2 in August 1987 (the
Chernobyl explosion delayed Unit 2’s commissioning by 1 year). Construction of
a third unit began in 1985, but this was suspended in 1988 and subsequently
demolished. The originally planned fourth unit was never started. Each 1,500 MW
unit had two 750 MW turbines, with total annual generation being about 19,000 GWh.
Key
features of the Ignalina reactors are the graphite moderated tips on the
control rods and the absence of containment shields. Readers might recall that
both of these features were among the numerous causes of the Chernobyl explosion,
however it is important to note that the Ignalina reactors also included some
safety features that Chernobyl did not have.
A bit about RBMK reactors
The 2
Ignalina reactors were RBMK-1500’s, which are water-cooled, graphite-moderated channel-type
power reactors rated at 4,800 MWt or 1,500 MWe (after the Chernobyl accident,
the RBMK-1500 reactors were de-rated to 4,200 MWt or about 1,350 MWe).
So
while the RBMK is largely equivalent to western boiling water reactors (BWR), a key difference is that each fuel assembly is
housed in a separately cooled channel that requires an even distribution of
coolant.
Decommissioning the Ignalina reactors
In
1999 Lithuania agreed to close both Ignalina reactors as a condition of
entering the EU, for which the EU agreed to contribute €820m towards the
decommissioning & decontamination costs. Decommissioning was as follows…
· Unit 1 was shut down on 31st December 2004 after
21 years of commercial operation.
· Unit 2 was shut down on 31st December 2009 after
22 years of commercial operation. Removal of spent fuel began in February 2011.
The wider picture of decommissioning
Ignalina
is obviously only 1 of many nuclear stations that are approaching the end of
their technical, economic or political lives A few comments…
· The political life of a nuclear station is obviously very
fickle as we’ve seen with the abrupt changes of direction in Germany and Sweden to name just a few.
· Languishing wholesale prices in many markets are essentially
squeezing nuclear out.
The
number of nuclear stations planned for closure is steadily climbing as these
issues bite…
· Europe - an expected increase from 76 closures in 2015 to
about 110 by 2020.
· United States – about 12 planned closures by 2025.
· Japan – about 5 planned closures.
· Britain – about 15 planned closures between 2023 and 2035.
Given
that it seems to take about as long to decommission and dismantle a nuclear
station as it takes to build one, there will be a lot of work to be done.
South Africa – proposed new nuclear station hits a big bump
Introduction
South
Africa has been quietly planning its next nuclear power station, but that
process recently hit a big bump in the road when a High Court ruled that the
Government’s actions were unconstitutional and illegal. This article examines
those rulings.
The process to date
Key
aspects of the process to date include…
· September 2011 - Energy Minister Dipuo
Peters signed off a
proposal for 9,600MW of nuclear capacity that was to go to Cabinet for a
decision by the end of 2011.
· November 2011 - Cabinet’s approval to establish the National
Nuclear Energy Executive Coordination Committee (NNEECC) at its meeting. There
was media comment that the NNEECC would be authorised to approve construction
contracts without further reference to cabinet.
· April 2016 – two site license applications are submitted to
the National Nuclear Regulator for approval, one for Thyspunt, in the Eastern Cape and the other for Duynefontein, in the Western Cape just north of Koeburg.
The big bump
Understandably
various lobby groups were upset with the process (ostensibly around the lack of
debate, consultation and transparency) and took inter alia the Minister, the President, the Regulator and Eskom to
the High Court in the Western Cape. Key features of the case include whether
various documents and agreements were tabled in accordance with legislation. The
ruling declared inter alia
that…
· Agreements with Russia, the United States and with South
Korea were both unconstitutional and unlawful, and were to be set aside.
· Various decisions around procuring new nuclear generation
capacity made pursuant to the Electricity Regulation Act were unlawful and
unconstitutional, and were to be set aside.
The decision not to appeal the High Court ruling
Energy
Minister Mmamoloko Kubayi has decided not to appeal the High Court’s ruling. Pipes
& Wires will comment further as the Government makes its next move.
General stuff
Guide to NZ electricity laws
I’ve
compiled a “wall chart” setting out the relationship between various past and
present electricity Acts, Regulations, Codes etc in sort of a chronological
progression. To request your free copy, pick here. It looks really cool printed in color as an A2 or A1 size.
A bit of light-hearted humor
What
if price control had been around in the 1920’s and 1930’s ? A collection of photo’s
with humorous captions looks at some of the salient features of price control.
Pick here to download.
Wanted – old electricity history books
If
anyone has an old copy of the following books (or any similar books) they no
longer want I’d be happy to give them a good home…
· Distribution Of Electricity (WT Henley, the cable
manufacturer)
· Northwards March The Pylons.
· Live Lines (the old ESAA journal).
· The Engineering History Of Electric Supply In New Zealand.
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Disclaimer
These articles are
of a general nature and are not intended as specific legal, consulting or
investment advice, and are correct at the time of writing. In particular Pipes
& Wires may make forward looking or speculative statements, projections or
estimates of such matters as industry structural changes, merger outcomes or
regulatory determinations. These articles also summarise lengthy documents, and it is important that readers refer to those
documents in forming opinions or taking action.
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Consultants Ltd accepts no liability for action or inaction based on the
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