From the
editor’s desk…
Welcome
to Pipes & Wires #157. This issue begins with a wider look at solar and
feed-in tariffs, and then notes a decision in the US to reject the inclusion of
car chargers in a regulated asset base. We then take a quick look at the
closure of a lignite-fired power station in Australia in the context of system
security. We then present 3 articles that take us through the entire lifecycle
of nuclear generation. This issue then concludes with some thoughts on whether
Australia’s electricity markets are working.
Please
also note a correction to the article on reducing the asset beta for gas
pipelines in PW #156. The wording “how much less than 1” in the 3rd
paragraph implied that the market taken in aggregate has an asset beta of 1
when it is about 0.7. Comparison of the current asset beta of 0.44 and the
proposed asset beta of 0.34 with 1 instead of 0.7 could imply that regulated
pipes & wires businesses are believed to have less risk than is actually
the case.
So …
until next month, happy reading…
Emerging themes & trends
Some
of the industry themes and trends that are emerging include…
· 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.
· Concern over foreign ownership of critical infrastructure.
This issue seems to have escalated from one of energy security to one of
national security.
· Diverging views of the green lobby on nuclear energy. Some
environmental groups remain steadfastly opposed to nuclear energy, whilst other
groups are now supporting nuclear as a useful transition from coal to
renewables.
· An increasing recognition that improved asset condition
information is the next frontier for improved asset management decisions, and
from there to strengthened regulatory proposals (rates cases).
· 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.
Solar, wind, batteries & micro grids
US – how much is solar really worth to a distribution
network ?
Introduction
Some
promoters of roof-top solar claim that the benefits are substantial. This
article takes an analytical look at what the real value of roof-top solar might
be and examines a recent regulatory investigation of that value in the US state
of Arizona.
What are the bases for valuing roof-top solar ?
Some
of the bases for valuing roof-top solar include…
· Reducing peak demand at the point of transmission grid
connection. That is important if the distribution company pays a demand charge
to the transmission company.
· Avoiding peak generation. This is only really important if
that peak generation is expensive (eg. oil-fired) … if it is hydro plant like
the Snowy Hydro in Australia, then the avoided cost could actually be quite
low.
· Avoiding distribution growth CapEx. If that specific part of
the distribution network is unconstrained (ie. has plenty of capacity
headroom), then the avoided cost is pretty much nil.
· The value of the
energy exported into the grid. This should be no greater than the prevailing
cost of a kWh from any of the retailers trading on that network.
This
strongly suggests that solar energy exported into the network during the middle
of the day is actually not worth that much. Separate from and additional to
this issue is the reduced nett kWh imported by roof top solar customers that
leads to a reduced revenue contribution to the electric company (known as
“solar cost shifting”).
The Arizona Corporation Commission’s recent work
Over
the last few years, electric companies in the American south-west have steadily
attempted to rebalance their mix of fixed and variable tariffs (refer to Pipes & Wires #149, #151 and #154) to mitigate solar cost shifting. This has understandably
met with huge resistance from the roof-top solar industry and left regulators
struggling to find an analytically sound position.
In October
2015 the Arizona Corporation Commission (ACC) ordered that an evidentiary hearing be held to better
inform inter alia the solar cost
shifting debate. Following 3 days of hearings during August 2016, the ACC chose
to delay any specific decisions on solar remuneration rates. Mindful of the
Nevada decision (refer to Pipes & Wires #149), the ACC stated its
determination to find a good policy compromise.
Key features of the evidentiary hearing
The evidentiary
hearing is occurring within the previously established docket E-00000J-14-0023 entitled “In the matter of the Commission’s investigation
of value and cost of distributed generation”. The scope of the hearing included
presentation of studies and proposed methodologies on the cost of connecting
distributed generation, and the value associated with distributed generation.
Next steps
The
next steps include the ACC reaching its conclusions, and then publishing those
conclusions. Pipes & Wires will comment further as those conclusions are
published.
Aus – abolishing the regulated retail feed-in tariff in
South Australia
Introduction
Regulated
retail feed-in tariffs are coming to an end in many jurisdictions, in part
because governments are becoming uneasy about the subsidies they provide. This
article examines the abolition of the regulated retail feed-in tariff in South
Australia.
Re-capping exactly what feed-in tariffs are
A
feed-in tariff is the price paid to an embedded generator for the electricity
that they feed back into the distribution network. FIT’s have historically been
greater than the tariff at which the same electricity would be purchased from
an electricity retailer, essentially subsidising the cost of roof-top solar.
Feed-in
tariffs come in two types…
· Retail feed-in tariffs (R-FIT), which is the amount paid to
the embedded generator by an electricity retailer as payment for the
electricity (kWh).
· Distribution feed-in tariffs (D-FIT), which is the amount
paid by the electricity distributor.
Recent moves in South Australia
The
South Australian Government deregulated small customer standing contract retail
pricing in February 2013. For the previous decade, the Essential Services Commission Of South
Australia (ESCOSA)
had set retail standing contract prices for residential and small business
whilst retail competition also provided choice and potentially lower prices.
Whilst ESCOSA then ceased setting default standing contract prices, they
continued to set regulated retail feed-in tariffs pending the development of
adequate competition in that sector.
ESCOSA
recently abolished the minimum R-FIT, which was 6.8c/kWh. ESCOSA holds the view
that there is sufficient competition amongst retailers to buy electricity from
embedded generators (mainly roof-top solar) for suitable market prices to be
established.
For the avoidance of doubt, the D-FIT will continue to be
paid by SA Power Networks until 30th June 2028 to all solar customers that
installed before 1st October 2011. This
is a state government legislated scheme with a premium payment of
44c/kWh. A subsequent scheme for solar installations before 1 October
2012 will cease being paid a premium payment of 16 cents/kWh from 1 October
2016.
What this means for the various electricity sector
participants
So
what could abolishing the R-FIT mean for the various electricity sector
participants ? Here’s some observations…
· Retailers will have the opportunity to offer R-FIT’s lower
than the regulated R-FIT if that is what they determine the true value of
exported electricity to be. They may also have to offer higher R-FIT’s to
capture new solar customers.
· Roof-top solar customers may have to shop around for the
retailer offering the best deal.
· Non-solar customers may also shop around for the retailer
offering the best deal. As retailers adjust their R-FIT’s, the subsidy required
from non-solar customers to fund the R-FIT will presumably also adjust. Hence a
retailer that offers a high R-FIT to attract solar customers may also require a
high subsidy to fund that R-FIT and therefore lose non-solar customers who can
obtain a lower price from other retailers.
· The cost of grid-scale solar in front of the meter will
presumably set an upper limit to the R-FIT (a simple “make or buy” decision by
the retailer).
· All distribution customers will continue to contribute to
the D-FIT.
So it appears that this will create a delicate balancing act
for retailers, and it will be interesting to see how the various retail
offerings play out. It
will also be interesting to see what retail and solar/battery offers develop
over time for the substantial amount of PV export from those customers not being
paid a D-FIT premium, particularly with batteries receiving significant media
promotion.
Pipes
& Wires will re-examine this in a year or so to see what has happened.
US – making the best use of roof-top solar
Introduction
One of
the problems with roof-top solar is that it generates most of its electricity
during the hot, sunny periods of the day when domestic electricity consumption
tends to be lower. This lengthy article examines two interconnected issues…
· The changing shape of the traditional demand profile.
· The Hawaii Public Utilities Commission (HPUC) recent approval of a 2 year pilot program that will
give up to 5,000 of Hawaii Electric
Company’s (HECO) customers the option of choosing time-of-use (TOU)
tariffs designed to encourage consumption during the hot, sunny periods and
discourage peak period consumption that requires oil-fired generation.
The demand profile issue
We’re
all familiar with the typical domestic demand profile that climbs steadily from
early morning as people get up, then declines during the daytime period and
then climbs into the early evening period when people get home from work and
cook dinner, and then finally declines during the late evening as people go to
bed. Historically the peaks were greater in winter.
I say
typical because changes in technology have allowed the typical demand profile
to change. A couple of examples include…
· Starting back in the 1940’s when domestic air conditioning
became cheaper and summer afternoon and early evening peaks began to increase. Now
that air conditioners are dirt cheap this is now at the point where many
networks are peaking during summer (which has obvious consequences for component
de-rating).
· Development of demand management programs such ripple
control of hot water cylinders. This shifted the hot water load to the
night-time and mid-day troughs on the demand profile, using the thermal inertia
of the water in the cylinder.
· Development of off-peak storage heating. Again, this used
the thermal inertia of bricks and concrete in the heater cabinet or the floor
slab to shift space heating demand to the night-time troughs.
· The development of two-rate meters in the late 1980’s. This
encouraged loads such as pottery kilns and clothes dryers to be used at night,
shifting demand into the night-time troughs.
· The introduction of electric cars. Off-peak charging would
obviously fill the troughs (which Orion’s predecessor the Christchurch
Municipal Electricity Department promoted in 1917) and perhaps more importantly
shift some very substantial demand away from peak periods.
Each
of these overlays embodies a range of customer behavior, which will in part be
influenced by prices and perhaps more specifically by the customers’ ability to
see those prices in real time and their willingness to change their
consumption patterns. It’s probably fair to say that over the last 15 years or
so cheap air conditioners have probably eroded the improved network utilisation
that came from over 40 years of careful demand management, and we now have the
opportunity to correctly encourage electric car recharging into off-peak
periods.
Feeder over-loading
Some
of HECO’s distribution feeders are now becoming overloaded. Not overloaded from
demand in the traditional sense of “load”, but overloaded in the emerging sense
of embedded generation (but of course the feeders don’t make that distinction …
current is current, regardless of its direction). Mitigating this overloading
could be done in 1 or more of the following ways…
· Install bigger conductors, which obviously has a capital
cost that needs to be recovered through regulated tariffs.
· Reduce the injected generation during periods of low
“internal demand” to reduce the amount of “exported” electricity that is
overloading feeders. This would be contrary to the whole philosophy of
renewable energy, and also foregoes free energy.
· Shift “internal demand” from traditional periods into the
hot, sunny periods so that most of the roof-top solar electricity is used in
the house rather than exported into the network.
· Re-orient everyone’s solar panels to the north-west so they
generate when the evening peak is starting to climb.
HECO’s tariffs
The
basis of HECO’s TOU tariffs appears to be shifting “internal demand” from
traditional usage periods into the hot, sunny periods of the day. The following
tariffs have been proposed…
|
Period |
Oahu |
Big
Island |
|
Mid-day 9am to 5pm |
$0.148/kWh |
$0.104/kWh |
|
On-peak 5pm to 10pm |
$0.349/kWh |
$0.470/kWh |
|
Off-peak 10pm to 9am |
$0.219/kWh |
$0.321/kWh |
The
key differences from the existing tariffs are…
· The mid-day tariff is lower than the current tariff,
encouraging consumption.
· The on-peak tariff is higher than the current tariff,
discouraging consumption.
This
should encourage use of appliances such clothes dryers and dishwashers during
the day, and may also encourage up-take of ice-bank cooling (the opposite of
night-store heating). Of course this comes at the cost of installing TOU
metering, for which HECO has already filed a rate case that included $340m for
smart metering.
This
does show great promise, so Pipes & Wires will re-visit this issue in a
year or so.
Regulatory decisions
US – recovering the cost of electric car recharging stations
Introduction
It
would seem that electric car recharging stations are an integral part of energy
policy. This article examines a recent case in which the Kansas State Corporation
Commission (KSCC) denied a proposal by Kansas City Power
& Light (KCPL) to recover part of the Clean Charge Network cost
from customers, and also considers this in the context of a wider disconnect
between desirable policy outcomes on the one hand and paying for those outcomes
on the other hand.
KCPL’s proposal
KCPL’s
Clean Charge Network (CCN) originally planned to install more than 1,000
recharging stations throughout the great Kansas City are. It was originally
planned that $5.6m of the CCN’s capital cost of $16.6m along with about
$250,000 in annual operating costs would be recovered through KCPL’s regulated
tariffs by including that cost in the rate base.
The regulator’s response
The KSCC denied KCPL’s proposal for the following reasons…
· KCPL has failed to demonstrate a legitimate demand for the
CCN.
· While stimulating electric car ownership may be a worthwhile
objective, it does not fall within the scope of KCPL providing sufficient and
efficient service.
· Thoughtful location of recharging stations may encourage
electric car drivers to visit specific retail areas, so why should the cost of
the rechargers fall on KCPL’s customers.
· The view that between 70% and 80% of recharging occurs at
home, and that the number of recharging stations proposed by the CCN is
unnecessary.
· The number of electric cars expected to be within KCPL’s
network area by 2020 is expected to be much lower than the 12,000 estimated by
KCPL.
· The CCN is essentially a load-building program that should
be funded by shareholders, and not through regulated tariffs.
All in
all, a very vigorous denial from the KSCC.
The editor comments
One
context to frame this issue within is one branch of government encouraging
investor-owned electric companies to contribute to public policy objectives
whilst another branch of government won’t allow the cost of that contribution
to be recovered. Readers might remember a similar occurrence with Baltimore Gas
& Electric’s (BG&E) smart metering proposal a few years ago … a
great contribution to energy policy, but all of a sudden not so great when it
came to recovering the costs through regulated tariffs.
NZ – determining the WACC for electricity distribution
Introduction
The Commerce
Commission recently released its cost of capital decision that will apply to
customised price-quality (CPP) proposals made by electricity distribution
businesses from the 30th September 2016. This article examines the
key features of that determination.
Regulatory framework
The regulatory
framework for setting the WACC is set out in clauses 5.3.22 to 5.3.29 of the Electricity Distribution Services Input Methodologies Determination 2012. This determination is made pursuant to Part 4 of the Commerce Act 1986.
Key features of the WACC’s
Key features of
the Vanilla WACC’s include…
|
CPP period |
Mid-point |
67th
percentile |
|
3 years |
4.83% |
5.30% |
|
4 years |
4.85% |
5.31% |
|
5 years |
4.85% |
5.32% |
System operations & security
Aus – closing thermal generation in Victoria
Introduction
Closing
thermal generation ostensibly to reduce CO2 emissions seems to be an
emerging trend. This article examines the expected closure of the Hazelwood power station in the Australian state of Victoria.
A bit about Hazelwood
Hazelwood
is an 8 x 200 MW lignite-fired steam turbine station located in the Latrobe
Valley, about 150km east of Melbourne. The station was built between 1964 and
1971, and over time has supplied up 25% of Victoria’s base load.
Hazelwood
was originally owned by the State Electricity Commission of Victoria (SECV). In 1996 Hazelwood was sold to a consortium led by
International Power (92%) for $2.35b after which a further $885m was invested
in new boilers and turbines. Hazelwood is currently 72% owned by Engie and 28% owned by Mitsui.
The expected closure
At the
time of writing this article, Engie is expected to decide whether to close
Hazelwood as part of its October board meeting.
There is some media comment, however, that Engie has already advised the
Victorian government that it is likely to close Hazelwood as soon as 1st
April 2017.
The various viewpoints
Understandably
there are a wide range of viewpoints on the expected closure of Hazelwood…
· The closure couldn’t come soon enough for the environmental
lobby. A little research reveals that Hazelwood was the target of
environmentalists over localised air quality before CO2 became an
issue.
· The 500 employees and 300 contractors will presumably be
unhappy about the expected closure, but in all fairness Hazelwood’s closure has
been signaled for about 20 years.
· The state government seems nervous about job losses in an
already depressed area, and has been working on transition plan for displaced
workers.
· WorkSafe Victoria believes the station needed further
investment to remain safe. The owners appear unwilling to make that investment,
effectively forcing its closure.
The likely impact on system security
Views
on the likely impact on system security vary, and in particular the view that
coal-fired stations are unnecessary seems to assume that renewables will
adequately supply the base load. However the last few years have provided some
stark lessons that renewables might be okay as long as we get the right amounts
of sun, wind and rain in the right places at the right times but when the wind
stops blowing, the clouds gather and the rain and snow don’t fall where the
dams have been built the risk of blackouts increases (refer to the article in Pipes & Wires #152 about Tasmania’s recent hydro shortage).
The
Australian Energy Market Operator’s (AEMO) National Electricity Forecasting Report notes that although overall electricity consumption is
expected to increase by about 11% over the next 20 years, consumption of
grid-supplied electricity will increase by only about 0.7% as roof-top solar penetration
increases. Perhaps we need to ask the hard “what if” question … what if parts
of Australia have prolonged cloud cover and grey, gloomy days (a solar
equivalent to Tasmania’s recent low hydro inflows) on which solar panels have
significantly reduced output ? What type of generation will fill the gap in the
supply curve ?
So what is the right answer ?
So
what is the right answer ? Should Hazelwood remain open to provide renewable
buffering ? Given its age (almost 50 years), plant type (steam turbine) fuel
type (lignite), low efficiency, likely capital investment requirements and
likely standing costs Hazelwood is almost certainly not the best pick of the
estimated 7,000 MW of surplus generation in the National Electricity Market
(NEM) to remain open but the issue remains that some thermal generation will
eventually be needed to step into the supply curve during undesirable weather
conditions.
Nuclear
US – delivering on the Nuclear Promise
Introduction
In
late 2015 the Nuclear Energy Institute launched a 3 year program focused on
improving efficiency and safety, and driving down costs. This article examines
the Nuclear Promise, and looks at the wider context of downward cost pressure
across the entire generation sector.
Key features of the nuclear promise
The
Nuclear Promise has 3 strategic focus areas…
· Maintain operational focus (mainly focused around safety as
a top priority).
· Increase value (including electricity market reform).
· Improve efficiency (including a cost reduction target of
30%).
The wider context of downward cost pressure
The
nuclear industry faces the following issues, which are putting downward pressure
on costs…
· An abundant supply of natural gas at historically low
prices, allowing gas-fired generation to under-cut nuclear.
· Low growth in national (MWh) demand.
· Subsidies for renewable electricity that allow wind and
solar to under-cut nuclear.
Against
these, total nuclear generation costs per MWh have increased by 28% over the
last decade.
Improving the value proposition of nuclear generation
The
Nuclear Promise’s Strategic Plan sets out 4 building blocks, of which #2 is of
particular interest … “leverage federal and state policies to ensure monetary
recognition of nuclear energy’s value”. One of the specific actions is to
reform capacity markets by developing market mechanisms that value the
attributes of nuclear power plants.
The editor comments
Energy
markets that only pay for generated MWh seem to have created a race to the
bottom in which generation with very low short-run marginal costs (SRMC)
capture the $$$ and squeeze higher cost generation further up the supply curve,
even though that higher cost generation provides secure capacity. So there is a
definite need for additional market mechanisms to reward electricity products
such as peak MW and security.
UK – Hinkley Point C gathers speed amidst tightened scrutiny
Introduction
Pipes & Wires #156 noted that the UK government planned a review of the
proposed Hinkley Point C nuclear station soon after Electricité de
France (EDF) approved it. This article examines the findings of
that review, and also notes the issue of foreign ownership of critical
infrastructure.
Key outcomes of the review
The
focus of the review was mainly national security, and did not appear to address
any commercial (the controversial strike price of £92.50 per MWh) or technical (the
engineering difficulties encountered at Flamanville #3) issues. The key outcome of the review was a revised
agreement in principle with EDF that primarily restricts EDF from on-selling
its stake in Hinkley Point C without the UK government’s approval.
It would
appear that this new requirement is aimed at China General
Nuclear’s 33.5% stake in Hinkley Point C that the UK government now
appears nervous about. For their part, UK opposition parties are claiming that
the government already has the legal power to prohibit on-sale of a stake, so
in fact the new safeguards are not really new at all.
The new legal safeguards
The
key safeguards include…
· The UK government’s ability to prevent the sale of EDF’s
controlling stake in Hinkley Point C prior to completion of construction.
· The UK government will take a special share in all future
nuclear power stations that it can use to prevent changes in ownership or
part-ownership.
· The Office of Nuclear Regulation (ONR) will be able to require any nuclear site developers
or operators to notify it of any changes in ownership or part-ownership. This
will effectively extend the role of the ONR from that of a technical and safety
regulator to include national security aspects.
· Reforms to the government’s approach to ownership and
control of critical infrastructure to ensure that the national security
implications of foreign ownership are fully understood.
The thorny issue of foreign ownership of critical
infrastructure
Foreign
ownership of critical infrastructure has become a topical issue over the last
few months as the Australian government suddenly rejected 2 bids for the
AusGrid distribution business and now the UK government has put additional
safeguards around ownership of nuclear power stations.
A
little thought reveals the following confusing and possibly contradictory
issues…
· These concerns are not new. Back in 2008 the NZ government
prohibited the sale of a 40% stake in Auckland Airport to the Canadian Pension
Plan, and even further back (around 2002) the German government
expressed a clear preference for Ruhr Gas to be owned by a German company.
· Many of the countries that are now expressing concern about
foreign ownership have a policy of allowing foreign investment.
· Free movement of capital is generally expected in today’s global
economy, and indeed is one of the founding principles of the European Union.
The ability to prevent the sale of ownership stakes would seem to be
inconsistent with that free movement of capital.
· What about the government’s ability to regulate ? There is
no shortage of examples of the government regulating and controlling the price,
performance and safety of essential infrastructure that it doesn’t own.
US – retiring Diablo Canyon
Introduction
What
we thought were the traditional battle lines over nuclear power have become a
bit blurred over the last few years, especially as some factions of the green
movement are now advocating for nuclear. This article considers the plans to retire
the Diablo Canyon nuclear station in California, and notes the community
responses that seem to be advancing that trend of blurring the traditional
battle lines.
A bit about Diablo Canyon
Diablo
Canyon is a 2 x 1,120 MW pressurised water
reactor (PWR) station located near Avila Beach in San Luis Obispo County, about halfway between Los
Angeles and San Francisco. Following the start of construction in 1968 the
station was completed in 1973. However commissioning of the two units was
delayed until 1985 and 1986 respectively after an off-shore seismic fault line
was discovered and the reactors were reinforced.
The
units are licensed to operate until 2024 and 2025 respectively, after which
time they will have both been operating for 39 years.
The retirement plans
In
June 2016 Diablo Canyon’s owners, Pacific Gas & Electric (PG&E),
announced that it would not seek to extend the operating licenses beyond the
current expiry dates. PG&E applied to the California Public Utilities Commission (CPUC) to retire the station and to recover the retirement
costs through its regulated electric tariffs.
This announcement
came as part of PG&E’s migration from nuclear to energy efficiency,
renewables and storage, and saw PG&E align itself with some of its
traditional environmental adversaries.
The community’s response to the closure plans
We
might well imagine that the surrounding community and environmental groups
would welcome the closure, but that’s not what has happened…
· Six cities in the San Luis Obispo region have filed papers
with the CPUC asking them to reject PG&E’s retirement plan. Part of the
issue appears to be the loss of property taxes from Diablo Canyon’s operations,
for which PG&E proposes to pay $50m compensation.
· Lobby group Environmental Progress has also filed papers
with the CPUC asking them to reject PG&E’s retirement plan, and is claiming
that PG&E has inflated the cost estimates of extending the operating
licenses to strengthen the business case for closure.
· Labor unions traditionally support high-paid jobs for their
members, and as such don’t obviously align with the anti-nuclear position that
some labor unions may align with. The labor unions involved at Diablo Canyon
have supported PG&E’s retirement plan, but only after PG&E agreed to a
range of benefits including retaining staff for the remaining 9 years,
retraining and severance payments.
The wider policy context of the proposed closure
Pipes & Wires #147 examined the passing into law of California Senate Bill 350, which set some very bold energy goals including increasing
California’s existing target of 33% renewable electricity by 2030 to 50%, and
to double the end use efficiency of electricity and gas consumption. Given the
strengthened legislation and PG&E’s apparent plans to implement that
legislation, the CPUC might find it difficult to reject PG&E’s retirement
plan.
It
would be easy to focus on the many parallel threads of detail woven through
this issue and be side-tracked by the apparent changes in views, however it is
important not to lose sight of the wider issue of changing California’s energy
mix, and PG&E’s pro-active plans to lead rather than follow. Pipes &
Wires will follow up on this issue in a year or so.
Electricity markets
Aus – are the electricity markets working ?
Introduction
There
will undoubtedly be many views on electricity markets, including how well they
are working, and indeed whether they are working at all. This article examines
some recent reports from 2 of Australia’s energy regulators which have both
concluded that the respective electricity markets are working in different
contexts.
The market in New South Wales
Following
the introduction of retail competition on 1st July 2014, the
Independent Pricing and Regulatory Tribunal (IPART) recently reviewed the performance and competitiveness of the NSW retail
electricity market. IPART’s draft conclusions were…
· Prices have declined, due in part to changes in the
underlying cost of supplying smaller customers.
· The electricity products offered are more innovative and
include integrated solar and battery options, energy and communications
bundling, more flexible billing arrangements, and shifts away from the
traditional kWh-based charges.
· Six new retailers entered the market during the year ending
30th June 2016 in addition to the five retailers that entered the
market during the year ending 30th June 2015. These new entrants are
putting downward pressure on the incumbent retailers’ prices.
· Increasing numbers of small customers are shopping around
for their electricity, and potentially saving between $250 and $445 per year.
IPART’s
overall (draft) conclusion is that competition in the residential and small
business market segments is working well, and that a detailed review of retail
prices and profit margins is not necessary.
The market in South Australia
Following
some high wholesale prices in South Australia on 7th July 2016, the
Australian Energy Regulator (AER) investigated and reported as it is required to do. Figure 3 on pg 10 of the AER
report is particularly note-worthy as it clearly shows a pinch point between demand
and available capacity around 7pm. The AER’s key findings are…
· That the interconnection capacity between Victoria and South
Australia was materially reduced due to planned outages on the Heywood
Interconnector. It appears that while the upgrade work on Heywood was signaled to the market, its implications for reducing
interconnection capacity may not have been well understood.
· The 150kV DC Murray
Link was operating near its rated capacity of 220 MW.
· The closures of the coal-fired Playford B in October 2015 and the coal-fired Northern in May 2016 has increased South Australia’s dependence on
gas and wind.
· Only 20 MW of wind generation was available.
· The available gas-fired generation was reduced due to both a
planned outage at Torrens Island B3, and Pelican Point having been placed on a 48-hour recall in 2015.
· Limited gas supply and limited gas transmission capacity on
7th July reduced the ability of the remaining gas-fired generation
to operate.
The
AER’s overall conclusion is that the price spikes were caused by a convergence
of operating and structural features, and were not the result of market gaming,
lack of competition or abuse of market power.
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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investment advice, and are correct at the time of writing which may be anything
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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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