From the
editor’s desk…
Welcome
to Pipes & Wires #152. This issue focuses quite narrowly on a range of
happenings in New Zealand and Australia.
We
start with a look at some regulatory policy amendments, and then take a
critical look at the thorny issue of dry year security of supply in Tasmania
and New Zealand. We then have a quick look at the conclusions of South
Australia’s Royal Commission on the nuclear fuel cycle.
This
issue concludes with a look at some revenue and cost of capital decisions in
Australia, New Zealand and France. So … until next month, happy reading…
Regulatory policy
NZ – amending the transmission pricing methodology (TPM)
Introduction
Amending
the pricing of Transpower’s transmission services is one of the Electricity
Authority’s (EA) on-going streams of work. This article examines the EA’s
recently released second issues
paper.
The importance of correct transmission pricing
The
TPM defines how much each grid customer pays for its grid connection services
(just to be clear, it is not about Transpower’s overall revenue which will
remain between $950m per year and $1b per year until the next revenue reset).
The EA is concerned that the current TPM is complex and is sending the wrong
price signals to grid customers that in turn are resulting in inefficient
investment at a national level.
The regulatory framework
The
regulatory framework for this work is set out in Subpart 4 of Part 12 of the Electricity Industry Participation Code which sets out the requirements for the TPM. Section 12.79 includes the requirement for the EA to assess the TPM
against the EA’s statutory objectives in s15 of the Electricity Industry Act 2010 which requires the EA to promote inter alia the efficient operation of the electricity industry for
the long-term benefit of customers.
The existing TPM charges
The
existing TPM includes 3 major charges…
· A connection charge (about $128m per year) paid by customers
who use specific grid assets.
· An HVDC charge (about $150m per year) paid by the South
Island generators.
· An interconnection charge (about $639m per year) paid by direct
customers and EDB’s for their use of the “grid at large”. The EA is concerned
that the “postage stamp” nature of this nationally averaged demand-based charge
does not strongly reflect the benefits provided by the grid to individual
customers, nor the charges they pay.
Key features of the proposed TPM
Key
features of the proposed TPM include…
· The introduction of an “area of benefit” charge in which all
parties in an area that benefit from transmission services will pay a price for
those services that reflects the costs of providing those services. The EA
notes that some specific new assets turn connection assets into interconnection
assets, which then have their costs recovered by the less efficient
interconnection charge.
· A residual capacity-based charge that will collect the difference
between the total revenue requirement and the revenue collected from the “area
of benefit” charge. A key feature of the proposed TPM is the expected migration
of grid services from the “residual charge” to the “area of benefit” charge
over time, meaning that charges will better reflect the cost of providing grid
services and therefore provide stronger incentives to avoid or defer future
grid investment.
· A widening of the criteria for seeking a prudent discount
including if standalone generation would be a cheaper option or if transmission
prices are creating a material risk of a direct customer closing their business
(leaving stranded assets). This is expected to discourage stranding of assets
by investment in local generation.
· An optimisation feature in which grid customers can request
Transpower to reduce the value of “area of benefit” assets if there has been a
material reduction in the use of those assets.
The expected results
As
with most changes to pricing methodologies, there will be winners and losers … the
second issues paper includes a chart showing the expected $ per year per
household change for each EDB. Beyond that, we might expect to see differing
responses to grid investment from those of the past.
Next steps
The EA
will be receiving submissions until 5pm on Tuesday 26th July 2016.
For help with compiling a submission, pick here or call Phil on (07) 854-6541.
NZ – reviewing the principles for
distributed generation
Introduction
The
principles underpinning the prices charges to connect distributed generation to
a distribution network are currently regulated. This article examines the
Electricity Authority’s recently released consultation paper reviewing distributed generation pricing principles (DGPP).
The regulatory framework
The
regulatory framework is set out in s6.9 of Part 6 of the Electricity Industry Participation Code, and essentially specifies a minimum pricing position if
the DG operator and the EDB can’t agree on suitable terms.
The proposed removal of pricing principles from the Code
The EA
is proposing to remove the DGPP from Part 6 of the Code after identifying the
following concerns…
· Limiting the charge for connecting DG to a network to the
incremental cost does not promote efficiency (noting that a key statutory
objective of the EA is to promote efficiency) because it restrict EDB’s from
charging a price that includes a share of the common costs. This limits the
EDB’s ability to charge cost reflective prices, which is topical in the context
of the EA’s work on distribution pricing principles.
· DG operators may be narrowly incentivised by the ACOT
payments to reduce transmission charges during peak periods rather than being
encouraged to improve wider efficiencies such as avoiding or deferring security
of supply investment.
Next steps
The EA
will receive submissions on this issue until 5pm on the 26th July
2016. For help with compiling a submission, pick here or call Phil on (07) 854-6541.
System operations and security
Aus – what’s happened in Tasmania ??
Introduction
Tasmania
has a lot of hydro-electric generation, which probably fits well with most
peoples’ view of Tasmania as being green and leafy with reasonable rainfalls.
This article examines the impact of recent low rainfalls and considers the
wisdom of increasing dependence on renewable generation.
Overview of Tasmania’s electricity system
Key
features of Tasmania’s electricity system are…
· The system is predominantly winter loaded, with a maximum
demand of about 1,900MW.
· The system has an installed capacity of about 2,925MW. This
is broken down as follows…
· About 310MW is wind
· About 2,270MW is hydro
· About 345MW is thermal
· The system can also import up to 480MW (or export up to
500MW) via the Basslink undersea cable, giving Tasmania an effective installed capacity of about
3,400MW.
· Annual energy consumption is about 10,800GWh.
· Long-run average annual generation is about 8,700GWh,
however it is noted that the size and nature of many of the hydro catchments
introduces significant year-on-year variability in generation.
· Water storage averaged around 35% to 40% over the 2000 to
2010 period, with a low of 19% in 2008.
The
last two facts and figures in particular indicate that Tasmania is quite
dependent on annual refilling of all its hydro lakes.
Recent events
Several
significant events have recently occurred in Tasmania…
· The main combined cycle plant at Tamar Valley was
decommissioned in August 2015, following a convergence of low demand, high
hydro inflows and high imports from the Basslink cable.
· In December 2015 the Basslink cable experienced a fault.
This may take until May 2016 to return to service.
· Inflows into the major catchments are at record lows, with
storage also falling to record lows (less than 13% and falling as of late April 2016, but with some significant recovery in May due to heavy
rain).
Responses to low hydro inflows
The
immediate response has been to re-commission the combined cycle plant at Tamar
Valley and hire about 200MW of diesel generators.
Going
back in time, readers might be intrigued to note that a prolonged drought in
1967 and 1968 resulted in the 2 x 120MW oil-fired Bell Bay station being built on the Tamar River. The sole reason for
building Bell Bay was to provide dry year reserve, and not surprisingly it only
generated about every 5 or 6 years (readers might recall similar thinking
behind Marsden A in New Zealand). Development at Bell Bay included…
· Commissioning of the 2 oil-fired steam turbines in 1971 and
1974 respectively.
· Conversion of those 2 oil-fired units to gas in 2003 and
2004 respectively.
· Installation of 120MW of gas turbines in 2006 (now part of
Tamar Valley).
· Installation of a further 58MW gas turbine in 2009.
· Installation of a 210MW combined cycle plant in 2009.
· Decommissioning of the 2 original steam turbine units in
2009.
· Decommissioning of the combined cycle plant in 2015.
This
indicates that Tasmania built up a portfolio of about 620MW of thermal
generation, only to reduce it back to about 170MW by 2015.
Thinking about dry year security
Construction
of oil-fired steam turbines seemed to be the preferred way of de-risking
hydro-based systems with low levels of storage, and that has arguably stood the
test of time. There is no doubt that modern political pressures to reduce CO2
emissions have changed the way electricity planners think about thermal plant,
but as the companion article in this issue reveals that doesn’t mean a
withdrawal of all thermal plant.
NZ – keeping Huntly going for a few more years
Introduction
Pipes
& Wires (refer to PW #148) has previously examined the closure of various thermal
stations, particularly the possibility that the two remaining 250MW gas-fired
and coal-fired units at Huntly might close in late 2018. This article examines
the recent decision to retain those two units until the end of 2022.
Previous plant closures
Recent
plant closures were as follows (with the planned closure of Huntly noted in the
last row)…
|
Effective
date |
Closure |
MW withdrawn |
Cumulative
MW withdrawn |
|
October
2014 |
Huntly
#3. |
250 |
250 |
|
June
2015 |
Huntly
#4. |
250 |
500 |
|
September
2015 |
Otahuhu
B. |
400 |
900 |
|
Late
2015 |
Southdown. |
140 |
1,040 |
|
Late
2018 |
Huntly
#1 and #2. |
500 |
1,540 |
The
introduction of low marginal cost generation into the system has reduced the
annual GWh from the thermal stations. This left the respective owners with high
fixed costs but no corresponding revenue, prompting the inevitable question of
whether to decommission the stations. That in turn has led to considerable
anxiety about what would happen in the inevitable dry years and considerable
debate about whether Huntly really would close.
The decision
In
late April 2016 Huntly’s owner, Genesis Energy, entered into a range of bilateral contracts with the other
generators that will see Huntly #1 and #2 remain in service until December
2022.
Looking at this decision from various angles
Various
angles on this issue include…
· From a system operation and security angle, the decision is
a welcome victory for common sense (refer to the article on Tasmania in this
issue, and the articles on the UK in previous issues).
· From a climate change angle, this will undoubtedly be seen
as a disaster.
· From an economic angle it is probably the least cost option
… Huntly #1 and #2’s annual stand-by costs will probably be insignificant in
comparison to the economy-wide losses from a dry year.
· From a political angle which has to try and balance all
three issues (the trilemma) it would seem that the risk of a dry year shortage
is less desirable than losing popularity with the environmental movement.
What
we can be sure of is that this issue is not going to go away.
Nuclear energy
Australia – the Royal Commission reports back
Introduction
The
South Australian Government has been holding a Royal Commission into the
nuclear fuel cycle. Pipes & Wires examination of this issue began with #147 and continued into #150. This article examines the Final Report.
Terms of reference of the Royal Commission
The
terms of reference of the Royal Commission were to investigate the following 4
aspects of the nuclear fuel cycle as directly applicable to South Australia…
· Exploration and mining.
· Processing.
· Nuclear electricity generation.
· Storage and disposal of waste.
The Commission’s Final Report
Key
findings of the Final Report include…
· That development of a disposal facility for international
used fuel and intermediate level waste could generate a nett surplus of about
$100b over a 120 year life. It is noted that social consent would be a major
factor in progressing this.
· Current state and federal mining regulations are sufficient
to allow a safe expansion of mining activity, however the approval requirements
are duplicative and could be simplified between the state and federal levels.
· The greatest risks from Uranium ore processing are chemical
(rather than radiation) and are well understood and managed. However there is
an over-supply of these services at present.
· That nuclear power generation is sufficiently safe to be
considered as part of the State’s energy mix, however it is not commercially
viable under the current market arrangements.
Some closing comments
The
final Report represents a pretty comprehensive analysis of the nuclear fuel
cycle and concludes that the risks of the various segments of the cycle are
well understood and manageable, but that the actual use of nuclear fuel (for
electricity generation) is commercially unviable.
Regulatory decisions
Aus – gas
under pressure in the Northern Territory
Introduction
Most readers will be familiar with the
requirements for covered gas transmission pipelines to have their allowable
revenue reset every 5 years. This article examines the access decision process
to date for the Amadeus
Gas Pipeline in Australia’s
Northern Territory for the 5 year regulatory period from 1st July
2016 to 30th June 2021.
A bit about the Amadeus Gas Pipeline
The
AGP stretches 1,629km from Darwin to Mereenie, Palm Valley and Alice Springs,
and has a capacity of about 100TJ per day. The major connected user of the AGP
is the Power & Water Corporation, for the supply of its gas-fired generation.
The legal framework
The
AER’s powers and duties, including with respect to regulating the AGP, are set
out in the National Gas Law (NGL) and the National Gas Rules (NGR). The NGL requires the AER to perform its functions in
a manner likely to contribute to the National Gas Objective “to promote
investment in, and efficient operation of, natural gas services for the long
term interests of consumers of natural gas with respect to price, quality,
safety, reliability and security of supply of natural gas”.
The
determination process to date
The
following table sets out the decision process to date…
|
Component |
Proposed
access arrangement |
Draft
decision |
Revised
access arrangement |
Final
decision |
|
Total
revenue requirement |
$140.3m |
$110.7m |
$134.8m |
|
|
Gearing |
60% |
60% |
60% |
|
|
Nominal
vanilla WACC |
8.3% |
6.0% |
8.6% |
|
|
Opening
capital base |
$120.6m |
$112.2m |
$119.5m |
|
|
CapEx |
$29.9m |
$26.5m |
$29.7m |
|
|
OpEx |
$62.8m |
$62.8m |
$63.1m |
|
Pipes & Wires will comment further once
the final decision emerges.
NZ – setting the WACC for electricity and airports
Introduction
The Commerce
Commission recently released its cost of capital decision for the year ending 31st March 2017 for…
·
Electricity
distribution businesses.
This article
examines the key features of that determination.
Regulatory frameworks
The regulatory
frameworks are set out in…
·
Clauses 2.4.1 to
2.4.7 of the Electricity Distribution Services Input Methodologies Determination 2012, and
·
Clauses 5.1 to 5.7
of the Commerce Act (Specified Airports Services Input Methodologies)
Determination 2010.
Key features of WACC’s
Key features of
the gas distribution WACC’s include…
|
|
25th
percentile |
Mid-point |
67th
percentile |
75th
percentile |
|
Vanilla WACC |
4.59% |
5.31% |
5.78% |
6.03% |
|
Post-tax WACC |
4.05% |
4.77% |
5.23% |
5.48% |
Key features of
the Wellington Airport WACC’s include…
|
|
25th
percentile |
Mid-point |
75th
percentile |
|
Vanilla WACC |
5.35% |
6.33% |
7.32% |
|
67th percentile Vanilla WACC |
5.16% |
6.14% |
7.12% |
Aus – the
Queensland electricity transmission determination
Introduction
The electricity transmission grid owner in
the Australian state of Queensland, Powerlink, recently
submitted its regulatory
proposal (rate case) to the Australian Energy Regulator for the
five year period from 1st July 2017 to 30th June 2022.
This article examines the key features of Powerlink’s proposal and in
particular how it expects to treat the impact of emerging technologies.
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 transmission determinations are principally made
pursuant to Chapter 6A
of the Rules.
A bit
about the assets
Powerlink is 100% owned by the Queensland
state government. It’s assets include 15,000km of lines and cables at 66kV,
132kV, 275kV and 330kV, and 135 substations over the 1,700km stretch from north
of Cairns to the NSW border.
Powerlink’s
views on emerging technologies
Powerlink’s proposal clearly notes that emerging
technologies are changing both the nature and volume of the demand for
transmission services. Key features of Powerlink’s thinking include…
· A lesser
role for the transmission of centrally generated electricity as more customers
install rooftop solar.
· Reduction
of the need for grid investment to cover short duration peaks as improving
battery technologies flatten the demand profile.
· Significant
shifts in the timing and magnitude of demand peaks due to solar, batteries and
electric car recharging.
· How
pricing for rooftop solar can fairly fund existing assets.
The AER’s acknowledgment and treatment of
these issues will prove critical in obtaining a determination that correctly
incentivises future investment.
The
determination process to date
The determination process to date includes
the following…
|
Parameter |
Proposal |
Draft determination |
Revised proposal |
Final determination |
|
CapEx |
$957.1m |
|
|
|
|
OpEx |
$976.7m |
|
|
|
|
Opening RAB |
$7,237.9m |
|
|
|
|
WACC |
6.04% |
|
|
|
|
Regulatory depreciation |
$623.2m |
|
|
|
|
Total smoothed revenue |
$4,017.2m |
|
|
|
Pipes & Wires will comment further as
this determine progresses.
France – gas
under pressure
Introduction
The
French energy regulator, the Commission de Regulation de l’Energie (CRE) has been compiling the tariff that will apply to the gas
distribution operator GRDF for the control period starting on 1st July
2016, known as ATRD5.
A bit about GRDF
Gaz Réseau Distribution France (GRDF) supplies about 11,000,000 end-use customers with gas
distribution services throughout France from its 196,000km of pipelines. GRDF
itself is a subsidiary of ENGIE which owns and operates 300,000km of gas
pipelines in 10 countries.
Legal framework
The
CRE derives its statutory powers from the Code de l’Energie, which was adopted into French law on 13th July
2005. In particular, Article L452 sets out the framework for gas transmission and
distribution tariffs.
The proposed ATRD5 tariff
Major
features of the ATRD5 tariff are…
· A proposed 2.8% tariff increase compared with the 11.7%
sought by GRDF.
· An escalation of 0.8% per year.
· Some ambitious productivity targets.
· A proposed WACC of about 5%.
Pipes
& Wires will comment further on ATRD5 as the CRE releases its final
decision.
Aus – the
Tasmanian electricity distribution determination
Introduction
The electricity distributor in the Australian
state of Tasmania, TasNetworks, recently
submitted its regulatory
proposal (rate case) to the Australian Energy Regulator for the
two year period from 1st July 2017 to 30th June 2019.
Readers may recall that the Tasmanian government amalgamated its transmission
grid Transend with its distribution business 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.
A bit
about the assets
TasNetworks distribution network comprises
22,400km of lines and cables, 18 large distribution stations and 33,000 small
distribution substations. These assets supply about 284,000 customers.
One of the features of TasNetworks is that because
it was originally vertically integrated as the Hydro Electric Commission there
were more transmission substations and few distribution substations.
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 transmission 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 |
$235.6m |
|
|
|
|
OpEx |
$123.1m |
|
|
|
|
Opening RAB |
$1,646.7m |
|
|
|
|
WACC |
6.04% |
|
|
|
|
Regulatory depreciation |
$107.2m |
|
|
|
|
Total smoothed revenue |
$493.3m |
|
|
|
Pipes & Wires will comment further as
this determine progresses.
Recent client projects
Here’s
a sample of work done for clients over the last few years that demonstrate the
breadth of skills, insight and experience that is available from Utility
Consultants....
· Advising a major equipment supplier on battery and solar
trends.
· Leading an energy trust workshop on future trends for the
distribution industry.
· Facilitating an executive workshop on the future trends and
issues for the distribution industry.
· Advising a major global investment bank on the revenue and
capital cost characteristics of the New Zealand generation industry.
· Assessing the investment characteristics of proposed CapEx
increases to an investor-owned electric network.
· Assessing three EDB’s asset management practices against ISO
55000:2014.
· Assessing an EDB’s compliance with the lines – generation
separation requirements of the Electricity Industry Act 2010.
· Assessing an EDB’s compliance with the Electricity Industry
Participation Code.
· Compiling safe operating procedures for a wide range of
distribution switches.
· Advising an investor on the investment characteristics and
regulatory constraints of small hydro development and grid connection.
· Reviewing the engineering aspects of an EDB’s lines pricing
methodology.
· Advising a major global consultancy on specific features of
emerging electricity transmission and distribution regulatory regimes,
including period length, potential for re-opening determinations, caps &
collars, total expenditure levels and incentive mechanisms.
· Examining the economic efficiencies of an EDB’s pricing
methodologies.
· Advised on the wider philosophical and potential tax issues
of the way consumer discounts are paid by EDB’s.
· Prepared an independent engineer’s report to justify
proposed alternative asset lives.
· Advised an electricity business on the regulatory
implications of bringing externally contracted field services back in-house.
· Identified economic and regulatory arguments to support
inclusion of transmission interconnection charge risk into network tariffs.
· Advised lines businesses on a regulator’s proposed treatment
of CapEx and OpEx.
· Advised an international investor on gas distribution policy
and regulatory trends.
· Identified national energy policy implications for lines
businesses.
· Assisted a lines business to identify the burden of proof
implied by regulatory determinations.
· Suggested amendments to a gas transmission AMP to strengthen
the economic arguments.
· Identified electricity network investment characteristics as
part of an acquisition study.
· Developed an AM framework for a gas distribution business to
link AM to regulatory requirements.
· Identified OpEx – CapEx tradeoffs for an electricity lines business.
· Performed various substation growth and reinforcement
assessments.
· Performed network physical and business risk studies.
· Compiled disaster recovery and business continuity plans.
Pick here to download a profile of recent projects, or here to contact Phil.
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…
· Economic Operation Of Power Systems
(Kirchmayer).
· Distribution Of Electricity (WT Henley, the cable
manufacturer)
· Northwards March The
Pylons.
· Two Per Mile.
· 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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