Pipes & Wires
From the editor’s desk…
Welcome
to Pipes & Wires #201 … this issue starts with a look at the recent
downgrading of NZ’s gas reserves, followed by a look at the task force report
on the closure of Liddell Power Station in Australia. We then look at a
controversial regulatory decision favoring fixed monthly charges for rooftop
solar customers in the US.
We
then examine 3 pipes & wires regulatory decisions in the UK, NZ and
Australia respectively and conclude with 2 industry ownership reshufflings in
the US. So … until next month, happy reading…
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Recent client projects
Recent
client projects include…
· Estimating the costs of DERMS
(distributed energy resource management system) penetration for distribution
feeders for a large US electric company.
· Identifying leading practices in
behind-the-meter activities (eg. batteries, solar, smart data, VPP’s etc) for a
large US electric company.
· Identifying key learnings from the
transformation of a Dutch electric, gas and heat company for a large US
electric company.
· Identifying best Australian practices
in EV charging for a large US electric company.
· Identifying key features of demand
management in the Australian NEM for a large US electric company.
· Compiling a pricing model to reflect
asset investment levels to transmission grid exit level rather than averaged
over the entire network.
· Identifying best practices in
grid-scale and community-scale batteries for an Australian distributor.
· Identifying best practices in EV
charging on behalf of an Australian distributor.
· Recommending amendments to a security
of supply standard to better reflect demand density.
· Identifying best customer engagement
practices on behalf of an Australian distributor.
· Development of an asset management
journey aligned to ISO 55001.
· Identifying learnings from the RIIO –
ED1 reset on behalf of an Australian distributor.
· Developing a smart metering strategy.
· Advising on likely available electrical
contractors.
· Undertaking a customer survey to identify
customer preferences for off-peak EV recharging.
· Developing a strategy for complying
with the related party transaction provisions.
· Advising on the regulatory implications
of an aging timber transmission pole fleet.
· Compiling some introductory thoughts on
digital transformation and blockchain.
· Facilitating a series of client
workshops to better understand asset information criticality and in-service
failure risk.
· Assessing the strength of asset
management practices.
· Reviewing recent AER decisions to
understand the expectations around asset management practices and methods.
· Reviewing the AER’s recent treatment of
network transformation expenditure.
· Compiling overhead conductor and wooden
cross-arm fleet strategies.
· Identifying the issues around
customer-owned lines on private land.
· Developing a risk-based tree trimming
strategy.
· Developing an EV charging strategy.
· Analysing transmission charges as a
percentage of total electric bills.
· Compiling a strategy for improving the
resilience of a sub-transmission network.
· Developing a best-practice guideline
for smart metering.
Cool multimedia stuff
CEGB
Midland Region website
Any readers who worked for the CEGB in the
1960’s might be interested in the CEGB Midland Region website.
Asset management
and asset strategy podcasts
My colleagues at the UMS Group have put
together a series of podcasts on asset management and asset
strategy, including an
interview with me on how to make asset
management happen in small companies. This
has also been republished as a short
narrative.
Energy mix and grid security
NZ – gas
under pressure
Introduction
Readers might remember the downgrading of
the Maui gas fields’ expected remaining reserves back in 2005. This article
examines the much more recent downgrading of the Pohokura gas fields’ expected
remaining reserves.
The
recent Pohokura downgrade
Pohokura’s estimated recoverable reserves
were recently reassessed downwards by about 217 PJ in early 2020. To provide
some useful context, NZ’s annual gas consumption is about 180 PJ (of which
Pohokura supplies about 40%), so that downgrade represents about 14½ months
consumption. Fortunately other gas fields have been reassessed upwards, as
follows…
· Mangahewa
(52 PJ)
· Kapuni
(54 PJ).
· Turangi
(65 PJ).
· Kupe (30
PJ).
· Maui (38
PJ).
So these upgrades totaling 239 PJ give a
nett increase of about 1½ months gas supply.
The
wider gas supply scene
As at January 2020, NZ’s proven gas
reserves were about 2021 PJ, or about 11¼ years supply at current consumption
rates. A quick scratch up of some approximate numbers for comparison is as
follows…
|
Country |
Reserves (km3) |
Annual consumption (km3) |
Expected supply (years) |
|
Russia |
47,805 |
444 |
108 |
|
Iran |
33,721 |
223 |
151 |
|
US |
15,484 |
846 |
18 |
|
China |
5,444 |
307 |
17 |
|
NZ |
66 |
5 |
13
(close enough to 11¼) |
So while NZ is not alone in having just
over a decade’s indigenous gas supply, that’s not long in terms of finding and
developing new supplies especially if gas is going to be the transition fuel.
Aus –
the Liddell closure taskforce reports back
Introduction
Pipes
& Wires #192 and #196
examined the Government
task force that was
established to examine the intended closure of the 4 x 500 MW coal-fired
Liddell Power Station in the Hunter Valley of New South Wales. This article
examines the final report and the Government’s response.
Recapping
the previous work
On the back of AGL’s intended closure of
Liddell in 2022 (later extended to 2023), Pipes & Wires #192 noted the
establishment of the task force and that a particular concern was wholesale
price spiking and security decline in the NEM similar to when Hazelwood closed.
Pipes & Wires #196 examined the draft
report which
noted that…
· Liddell’s life could be extended by a further 3 years to 2026, at
an apparent cost of $300m, but it would still be likely to prove unreliable,
and hence should not be relied upon.
· Life extension of Liddell could curb gas expansion projects such
as Tallawarra
B.
· It is expected that this life extension would need to be taxpayer
funded, as AGL has previously indicated that it is unwilling to fund life
extension.
· That pumped storage, gas and batteries could feasibly replace
Liddell.
The
final report
The task force delivered its final
report in April 2020,
which included a wide range of conclusions and recommendations. Taken in
aggregate, the broad conclusions are…
· Wholesale
prices would rise about $5 per MWh to $10 per MWh more than they otherwise
might.
· Publically
announced battery and generation projects will more than offset the loss of
system reliability, but a decline in grid security may still emerge.
Key recommendations include…
· That a policy
framework to address the reliability impact of coal closures be developed through
the COAG Energy Council (there seems to be at least some nervousness about the
price and security impacts of closing Liddell, based in part at least on the
observations of closing Hazelwood).
· That
non-market barriers to developing replacement generation must be dismantled.
· That
demand response and DER integration be used as a short-term response to the MWh
gap.
As always, interested parties should read
the full report.
The
Government’s response
Key features of the Government’s
response (released in
September 2020) include…
· A clear
statement that the observed price increases and security decline arising from
the Hazelwood closure have not been addressed for the Liddell closure, and that
further price rises and security declines are unacceptable.
· Setting
a target of 1,000 MW of dispatchable generation to be developed by the private
sector for the 2023/24 summer.
· Continued
support of new gas-fired generation.
· Signaling
government intervention if private sector commitment have not emerged by April
2021. This includes private-sector life extension of Liddell, but stops short
of Government funding for a Liddell life extension.
This is obviously a significant energy
trilemma issue, so Pipes & Wires will comment further as news emerges.
Regulating
emerging technologies
US –
regulator upholds “sun tax”
Introduction
The idea that fixed monthly charges are a
“tax” on solar seems to be one of the well-established themes of the
ideological battle between rooftop solar and electric distribution companies.
This article notes a recent decision by the Alabama Public Service Commission to
not only uphold Alabama Power’s solar tariff, but to increase it.
Alabama
Power’s solar tariff
Alabama Power currently charges an
additional $5 / kW / month to connect rooftop solar to its network, hence a
customer with a 5kW panel would pay an additional $25 per month. This is
referred to as a capacity reservation fee, or a firm back-up fee.
Challenges
to the tariff
Various groups opposed that tariff, which
led to the Southern Environmental Law Center (SELC) petitioning the Alabama
Public Service Commission (APSC) back in 2018 to prohibit Alabama Power from charging
a solar tariff, claiming that it reduces the benefit of rooftop solar (which it
undoubtedly does, and which electric companies have never denied).
Alabama Power in turn asked the APSC to (i)
dismiss the petition, and (ii) allow the tariff to be increased to $5.42 / kW /
month, claiming that the existing $5 / kW / month was insufficient to offset
the reduced kWh revenue.
The APSC
decision
In a 3 – 0 decision, the APSC not only voted to dismiss the
petition, but to allow Alabama Power to increase its solar tariff to $5.41 / kW
/ month.
The
various views on the decision
The various views on the decision have
fallen into a fairly predictable pattern…
· The
various solar and environmental have criticized the decision, claiming that it
is a regressive step for Alabama, out-of-step with other states policies, and
that the APSC along with Alabama Power continue to prevent the transition to
cleaner energy.
· Alabama
Power in turn reiterates its argument that rooftop solar customers who want the
security of grid connection need to pay for that connection.
Network regulatory decisions
UK – National Grid responds to RIIO –
T2 draft
Introduction
Pipes & Wires #200 examined Ofgem’s draft RIIO – 2 price controls that will apply to inter alia National Grid for the 5 year period starting on 1st
April 2021. This article firstly notes National Grid’s public response to the draft, and then considers the
wider aspect of balancing price and supply quality.
National Grid’s concerns
National
Grid had proposed about £10b of electricity and gas transmission
investment focused on long-term resilience and nett-zero CO2 transition,
and has expressed concern that the RIIO – 2 draft rejected 50% of the proposed
electricity investment and 40% of the proposed gas investment. That 50% cut of
electricity investment includes an 80% cut in the proposed £3b
reliability spend, which National Grid estimates will increase the risk of
asset failure by about 24% and require anything up to 100 years to replace
aging assets.
National
Grid has cited the specific example of replacing 1 of the 2 cables supplying
Sheffield at a cost of £40m, due to deterioration. In turn,
Ofgem has commented that 1 condition assessment dating from 2015 is
insufficient to justify this project (and if that is in fact correct, I would
be inclined to agree).
Ofgem
also notes that it is providing regulated suppliers with the opportunity to
strengthen the business cases for such projects.
Wider aspects of balancing price and
supply quality
Balancing
price and supply quality is obviously an issue of national importance that
should be evident to all, with the consequences of getting it wrong running
into billions of pounds.
Without
a doubt, blackouts in general seem to be occurring more frequently, but in this
context we need to be focused solely and narrowly on those blackouts caused by
lack of replacement spend caused by excessive price cuts. What is concerning is
that 2 very knowledgeable organisations have come up with such significantly
different answers (and that is not to say that this has never occurred before,
but it is none-the-less concerning).
Next steps
Pipes
& Wires will comment further when Ofgem releases its final decisions around
December 2020.
NZ – WE* draft transition back to a DPP
Introduction
The regulatory framework for electricity distribution
businesses that do not meet the customer ownership requirements set
out in s54D of the Commerce Act 1986 provides for default regulation by a default price-quality path (DPP), or a customised price-quality path (CPP) if the business believes that
the allowable DPP revenue is insufficient. This article examines the Commerce
Commission’s recently published draft decision for Wellington Electricity’s (WE*) transition
back to a DPP when its CPP ends on 31st March 2021.
Key features of the WE* CPP
WE* is subject to a 3 year CPP, concluding
on 31st March 2021. Key features of the WE* CPP include…
· A starting price of $105.206m.
· A rate of change of CPI – 0%.
· A maximum SAIDI of 40.63 for each of
the 3 years.
· A maximum SAIFI of 0.625 for each of
the 3 years.
· Have a minimum resilience index of 20,
40 and 60 for each of the 3 years (which specifically relates to improving
earthquake resilience to a New Building Standard of 67%).
The transition back to the DPP
The WE* CPP
ends on 31st March 2021, after which a 4 year DPP will apply to
align with the current 5 year DPP period ending on 31st March 2025.
The draft decision
Key
features of the draft decision include…
· Setting the 1st April 2021
starting price using a building blocks approach rather than simply rolling over
the CPP closing price. This is similar to the approach used to compile the
current DPP3 revenue control.
· Approving an adjustment to the base
year OpEx based on the 2021 earthquake readiness spend approved in the CPP
determination, instead of the 2020 actual spend.
· Not approving an adjustment to the base
year OpEx based on 2021 insurance premiums.
Next steps
Consultation
on the draft decision has now closed, and the Commission expects to publish its
final decision in late November 2020. Pipes & Wires will comment further
when that final decision emerges.
As
always, interested parties should read the full decisions documents.
Aus – the draft AA5 decision for the
Dampier – Bunbury pipeline
Introduction
It’s
been a while since Pipes & Wires has examined any of the major Australian
gas transmission pipelines. This article examines the draft decision for the
Fifth Access Arrangement (AA5) for the Dampier –
Bunbury Natural Gas Pipeline to set some context for the final
decision.
A bit about the DBNGP
The DBNGP is a 660mm welded steel pipeline
stretching approximately 1,600km, to link the Carnarvon Basin gas fields via
Dampier to Perth and Bunbury. The pipeline was built in 1984, and includes 27
compressor units at 10 locations. The current owner of the pipeline is DBNGP
(WA) Transmission Pty Ltd.
The regulatory framework
The
DBNGP is 1 of 3 gas transmission pipelines regulated by the Economic Regulation Authority
(of Western Australia). The regulatory framework includes…
· The National Gas (South Australia) Act 2008.
· The National Gas Rules.
· The National Gas Access (WA) Act 2009.
The decision process to date
The
decision process to date includes…
· January 2020 – DBNGP submitted its
proposed revisions to its original AA5 proposal.
· August 2020 – ERA published its draft
decision to (i) not approve the AA5 proposal, and (ii) require 53 amendments.
· October 2020 – DBP submitted a revised
(revised) AA5 proposal.
Next steps
Pipes
& Wires will comment further when the ERA releases its final decision.
Industry reshuffling
US – the
price of becoming a muni
Introduction
Pipes
& Wires #192 examined Chicago’s
proposed municipalising of Commonwealth Edison (ComEd) when its’ franchise
expires on 31st December 2020. This article examines the key
conclusions of the feasibility study.
Recapping
the ComEd situation and the muni proposal
ComEd
has supplied electricity to Chicago under a franchise agreement since 1947, and
which was last renewed in 1992 for a 29 year period. The agreement includes a
monthly franchise fee paid to the City, which along with electricity taxes
generates about $183m per year for the City.
A
key element of the muni proposal is that Chicago has an opportunity to define
its energy future … it was claimed that through municipalisation, Chicago could
accelerate decarbonisation and implement a progressive tariff structure that
ensures better prices for working-class Chicagoans. Pipes & Wires noted that in broad terms, it was
hard to see how a simple change of ownership would allow a significant
repositioning of ComEd on the energy trilemma.
Key conclusions
of the muni study
Readers will recall that Chicago
commissioned NewGen Strategies And Solutions to
estimate the costs of municipalising ComEd. Key conclusions of that study
include…
· That the
average annual electric rate would be greater for a muni than it would under
the existing ComEd franchise for the period 2020 to 2039.
· An
estimated asset purchase cost of about $4.9b.
· An
estimated cost of separating the ComEd network from parent company Exelon of
about $3.9b (mainly additional transmission and distribution assets, and
metering).
· A view
that it would take many years to establish a muni and get it to the point where
it could actually start achieving Chicago’s stated goals.
So municipalisation of ComEd would cost
Chicago about $8.8b.
The
editor comments
Chicago’s mayor has somewhat cryptically
commented that “municipalising does not appear to be financially feasible”,
which is probably no surprise to most of us. Pipes & Wires commented a few
editions ago that municipalisation could be a serious case of “be careful what
you wish for”, and it seems that has been borne out.
US – the
first of the mega-mergers gets rejected
Introduction
Pipes & Wires has examined many mergers
of US electric companies that cost around $10b to $15b. This article examines
Next Era Energy’s recently rejected merger with Duke Energy with an estimated value
of $60b, and considers whether this might set the scene for a wave of mega-mergers
of the already-big electric companies.
A bit
about Next Era and Duke
NextEra Energy owns about 46,000 MW of
generation, and supplies over 5,000,000
customers in 16 states and Washington DC. Annual
revenues are about $19b, nett income is about $3.4b, and total assets are about
$118b.
Duke Energy owns
about 51,000 MW of
generation, and supplies 7,700,000 electric
customers in North Carolina, South Carolina, Florida, Ohio, Kentucky and
Indiana, and 1,600,000 gas customers in North Carolina, South Carolina, Ohio,
Kentucky and Tennessee. Annual revenues are about $25b, nett income is about
$2.1b, and total assets are about $159b.
The merged company would therefore have had
about 97,000 MW of generation, and supply 12,700,000 electric customers and
1,600,000 gas customers in 21 states and Washington DC. Annual revenues
would’ve been about $44b, nett income would’ve been about $5.5b, and total
assets would’ve been about $277b. The market capitalisation of about $200b
would’ve been far above the next largest electric companies (Dominion Energy at
$65b, and Southern
Company at $57b).
The
proposed deal
No details of the deal structure appear to
have been made public, other than it was proposed as a “merger”, however the
rise in Duke’s stock price suggested that its shareholders favored some sort of
amalgamation. In any case Duke swiftly rejected NextEra’s approach, to which
NextEra responded that it would not pursue a hostile takeover.
Key issues
The following issues would’ve made the
merger tough work…
· Duke’s
15,000 MW of coal-fired generation being seen as inconsistent with NextEra’s
emphasis on renewables.
· The need
for an overwhelming number of regulatory approvals … 20+ state regulators, the Federal Energy Regulatory Commission, the Securities & Exchange Commission and
possibly the Federal Communications
Commission, the Nuclear Regulatory Commission and the
Department Of Justice.
· Possible
dilution of NextEra’s industry-leading price-to-earnings multiple of 28.
· NextEra’s
recently failed merger attempts with Oncor Electric Delivery (2016)
and Hawaiian
Electric (2017).
So although this merger was rejected in the
first instance, it may well have sown the seed for the other already-big
electric companies to think about merging.
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 classic historical photo’s with humorous captions looks at some
of the salient features of price control. Pick here to download.
A potted history of electricity
transmission
I’ve
recently compiled a potted history of electricity transmission. Pick here to download.
Wanted – old electricity history books
Now
that I seem to have scrounged pretty much every book on the history of
electricity in New Zealand, I’m keen to obtain historical book, journals and
pamphlets from other countries. So if anyone has any unwanted documents, please
email me.
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Disclaimer
These articles are of a general nature, they do not constitute 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.
Utility Consultants Ltd accepts no liability for action or inaction
based on the contents of Pipes & Wires including any loss, damage or
exposure to offensive material from linking to any websites contained herein,
or from any republishing by a third-party whether authorised or not,
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parties.