Pipes & Wires
From the editor’s desk…
Welcome
to Pipes & Wires #199, which starts with a look at transmission grid
pricing in New Zealand and some market rule changes in Australia to allow
trading of demand response.
We
then examine whether nett metering might come to an end in the United States,
followed by some electricity and gas distribution revenue decisions from
Australia. We then jump back to the United States to examine competition
concerns around an acquisition, and a possible exit from a bulk supply
arrangement. This issue concludes with a look at the gas exploration moratoria
in Australia under the broad theme of energy mix and grid security.
So …
until next month, happy reading…
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Cool multimedia stuff
Power
from the River (1947)
PW 199
This 22 minute video
examines the Waikato River catchment and the original North Island system
control back when it seems that Wellington rather than Auckland was the center
of New Zealand. It also seems that radio pick up (switching on the kettle) is
nothing new.
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.
Regulatory thinking and policy
NZ –
reviewing the transmission pricing methodology
Introduction
Pipes
& Wires #190 examined the
Electricity Authority’s (EA) draft transmission pricing methodology (TPM). This
article recaps the key features of the draft TPM, and then examines the recently
released revised cost-benefit analysis.
Recapping the draft TPM
Key
features of the draft TPM include…
· An overall “benefits based” approach in
which customers who benefit from specific investments would pay for them.
· Two new charges to replace the existing
RCPD (regional coincident peak demand) and HVDC (high voltage direct current)
charges…
· A benefits-based charge that will
recover the cost of (i) the 7 major existing investments and (ii) any new
investments.
· A residual charge to recover any remaining
costs in a way that does not distort incentives to invest in or use the grid.
· Making the new charges hard to avoid.
· Aligning the approach to the recently
released distribution pricing principles.
Not
surprisingly, those who face higher transmission charges are concerned by the
proposed changes.
The
revised cost-benefit analysis
In April 2020 the EA released a revised
cost-benefit analysis. Key features of
that revised analysis based on stakeholder feedback include…
· Amended
assumptions around grid-scale batteries, particularly about how installed
battery costs are unlikely to decline as rapidly as previously thought, and
better recognition of constraints to demand-shifting.
· Less new
generation (about 850 MW in the 2020 analysis, compared to between 1,000 MW to
1,500 MW in the 2019 analysis).
· Changes
to the way wholesale market features such as the value of water and part
dispatch of generation are modelled.
· A
downward revision of the expected TPM benefits, from between $200m to $6.4b in
the 2019 analysis to between $400m to $2.4b in the 2020 analysis.
The final
decision
In June 2020 the EA released its final
decision, which confirmed
the benefits charge and the residual charge proposed in the draft.
Next
steps
Pipes & Wires will provide further analysis
and comment as the TPM progresses, including Trustpower’s appeal to High Court.
Aus –
rule change to allow demand response trading
Introduction
Behind the most visible energy (MWh)
trading feature of wholesale markets are other markets that allow trading of
and paying for other electricity products such as peak demand (kW), frequency
keeping and demand response. This article examines a recent rule change in the
Australian National Electricity Market (NEM) that will allow large electricity
customers to not simply curtail demand but to trade that curtailing.
Explaining
demand response
Unplanned interruptions to electricity
supply (such as a generator or line failure) have traditionally relied mainly
on spinning reserve (hydro stations that were synchronised but running near
zero load) to meet that sudden excess of demand over supply. The other response
was of course interrupting controllable load, however the slow response of
legacy ripple relay injection plant limited the usefulness of this for sudden
supply interruptions (which is different to AUFLS for slow declines in grid
frequency). Technology improvements over many decades now allow instant
curtailing of designated demand through smart meters and similar devices.
The rule
change
In June 2020
the AEMC released the National
Electricity Amendment (Wholesale demand response mechanism) Rule 2020 No. 9 and the associated Final Determination. The key feature is that electricity customers
can now sell demand response to the Wholesale Market either directly or through
an aggregator by registering as a demand response service provider (DRSP).
Expected
benefits of demand response trading
The expected
benefits include…
· Demand response can now compete with other
supply – demand balancing mechanisms, such as peaking generation.
· It shouldn’t require too many changes to
retailer billing systems.
· The price at which customers are willing to
curtail demand becomes visible to all market participants, enabling customers
to respond directly.
The final
Rule will become operative on 24th October 2021 in time for the
2021/22 summer.
Regulating
emerging technologies
US – is
the end of nett energy metering nigh ?
Introduction
Improving technology and emerging thinking
around how valuable embedded generation actually is are reducing the need for
exported solar electricity to be bought by the electric company at the same
price it would sell electricity at. This article examines a rate case proposed
by Rocky
Mountain Power in the US state of
Utah that could prompt the end of nett metering in both Utah and in many other
states.
What
exactly is nett metering ?
Nett metering is where an accumulating
meter simple records the energy imported (bought from the electric company)
less the energy exported (sold back to the electric company), with a key
implication being that the export price is the same as the import price. The
original purpose of nett metering was to encourage the roll out of rooftop
solar (which it certainly did), whilst a key concern was that it valued exported
energy at the same price as imported energy.
The
history of nett metering in Utah
Electric companies in Utah have been
required to offer nett metering tariffs since 2008 under Title
54, Chapter 15 of the Utah Code. Around
2017 the Utah
Public Service Commission began revising its
nett metering rules which included a temporary tariff of 9.2 c/kWh and an
agreement that Rocky Mountain Power would schedule a rate case for the 2020
year.
Rocky
Mountain Power’s proposed rate case and the solar industry’s response
Rocky Mountain Power’s rate case proposes
to introduce a tariff of 1.5 c/kWh in 2021 which would apply to all rooftop
solar installed after the end of 2020. The signaled end of nett metering which had
already caused an approximate halving of rooftop solar sales from around 10,000
in 2017 to about 5,000 by 2019 prompted some in the solar industry to conclude
that Rocky Mountain Power would retain the 9.2 c/kWh tariff beyond 2020
(presumably from the view point that solar was now less of a threat so there
was no need to reduce tariffs any further).
Setting
a value for exported solar
This will always be an arguable point (much
like fixed monthly tariffs), with the key issue being that the initial nett
metering tariffs over-priced the value of exported solar and extracted a subsidy
from non-solar customers. Rocky Mountain Power argued that the existing nett
metering tariff of 9.5 c/kWh forced it to pay $2.3m for energy that would’ve cost
less than $1m from the market.
Pipes & Wires will re-examine this as
the Utah PSC determines Rocky Mountain Power’s rate case.
Network regulatory decisions
Aus – the SA and Queensland electricity
distribution revenue resets
Introduction
The Australian Energy Regulator (AER) recently released it Final Determinations for SA Power Networks, Energex and Ergon
Energy for
the 5 year regulatory control period commencing on 1st July 2020.
This article follows on from Pipes
& Wires #180, #186, #195 and #196.
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 135 at the time of writing).
Electricity distribution determinations are principally made pursuant to Chapters 6 of the Rules.
Key features of the process to date
Key features of the SA process
to date include…
Parameter |
Draft Plan |
Proposal |
Draft Determination |
Revised Proposal |
Final Determination |
CapEx |
$1,850m |
$1,741m |
$1,247m |
$1,712m |
$1,596m |
OpEx |
$1,468m |
$1,530m |
$1,585m |
$1,442m |
$1,574m |
Opening RAB |
Not stated |
$4,418m |
$4,393m |
$4,357m |
$4,361m |
Nominal WACC |
5.5% |
5.43% |
4.95% |
4.79% |
4.75% |
Depreciation |
$1,024m |
$1,144m |
$1,188m |
$1,219m |
$1,230m |
Smoothed revenue |
Not stated |
$3,915m |
$3,905m |
$3,916m |
$3,914m |
Key features of the Energex
process to date include…
Parameter |
Proposal |
Draft Determination |
Revised Proposal |
Final Determination |
CapEx |
$2,327m |
$1,793m |
$2,010m |
$2,000m |
OpEx |
$1,806m |
$1,942m |
$1,938m |
$1,932m |
Opening RAB |
$12,917m |
$12,887m |
$12,861m |
$12,875m |
Nominal vanilla WACC |
5.46% |
4.87% |
4.67% |
4.73% |
Depreciation |
$804m |
$756m |
$822m |
$883m |
Smoothed revenue |
$6,541m |
$5,840m |
$5,900m |
$6,010m |
Key features of the Ergon
process to date include…
Parameter |
Proposal |
Draft Determination |
Revised Proposal |
Final Determination |
CapEx |
$2,905m |
$2,151m |
$3,007m |
$2,276m |
OpEx |
$1,835m |
$1,973m |
$1,968m |
$1,963m |
Opening RAB |
$11,634m |
$11,553m |
$11,513m |
$11,534m |
Nominal WACC |
5.46% |
4.87% |
4.67% |
4.73% |
Depreciation |
$1,052m |
$997m |
$1,052m |
$1,103m |
Smoothed revenue |
$6,516m |
$5,788m |
$5,997m |
$5,926m |
This concludes Pipes &
Wires coverage of the SA and Queensland electricity distribution revenue
resets.
Aus – the Jemena gas distribution revenue
reset
Introduction
The Australian
Energy Regulator (AER) has recently released its Final Decision for Jemena
Gas Networks for the 5 year regulatory period commencing on 1st July
2020. This article examines the key features of the overall process.
A bit about Jemena Gas Networks
Jemena Gas Networks distributes gas to 1,400,000 customers
throughout the Sydney, Newcastle, Wollongong and regional centers through
25,000km of pipelines. Annual revenue is about $600m and EBITDA is about $370m.
The regulatory framework
Key
elements of the regulatory framework include…
· The National Gas (South Australia) Law 2008.
· The National Gas Objective.
· The National Gas Rules.
Key features of the process to date
Key
features of the process to date in nominal $$$ include…
Parameter |
Initial
Proposal |
Revised
Proposal |
||
Total
OpEx |
$1,037m |
$1,097m |
$1,092m |
$1,170m |
Total
nett CapEx |
$899m |
$791m |
$893m |
$865m |
Opening
RAB |
$3,353m |
$3,353m |
$3,331m |
$3,318m |
Return
on capital |
$826m |
$756m |
$766m |
$755m |
Nominal
vanilla WACC |
4.96% |
4.46% |
4.60% |
4.49% |
Regulatory
depreciation |
$410m |
$411m |
$445m |
$444m |
Smoothed
revenue |
$2,180m |
2,003m |
$2,091m |
$2,176m |
This
completes Pipes & Wires analysis of Jemena’s gas distribution revenue
reset.
Energy markets and tariffs
US –
acquisition raises competition concerns in the Lone Star State
Introduction
In addition to general competition law
prohibiting acquisitions that could increase market dominance, many energy
regulatory frameworks also include specific provisions to discourage vertical
or horizontal reintegration. This article examines the competition and
reintegration issues around the acquisition of El Paso Electric by a JP Morgan
fund that is affiliated to the Mesquite gas-fired power station in Arizona.
The players
The 3 players are…
· El Paso Electric is a
publicly listed electric company supplying 400,000 customers in west Texas and
southern New Mexico. Annual revenue is about $920m.
· Mesquite
power station comprises 2 blocks
of 625 MW gas-fired generation. One block is owned and operated by Salt River
Power, whilst the other is owned Southwest Generation (a JP Morgan affiliate)
and operated by Salt River Power.
· JP
Morgan is the ultimate
owner of the Infrastructure Investments Fund (IIF), a $12b fund.
The
proposed acquisition
IIF has offered $4.3b for El Paso. The
proposed acquisition has received regulatory approval from the Texas Public Utilities Commission and the
New
Mexico Public Regulation Commission.
The
competition issue
The competition issue arises from IIF
seeking to acquire El Paso whilst also being an affiliate of Mesquite. Specific
concerns include…
· That Mesquite’s
energy could be sold to El Paso on a self-dealing basis when the existing
Mesquite power purchase agreements expire in April 2021, meaning that El Paso’s
customers might be paying more for their electricity.
· That El
Paso’s existing generation could be instructed to buy gas hedges from JP Morgan
affiliates rather than on the open market.
Possible remedies include…
· Requiring
Mesquite to enter into a power purchase agreement with an unaffiliated entity
from April 2021.
· Imposing
an information disclosure regime to ensure that El Paso sources its wholesale
electricity and wholesale gas from the cheapest sources.
Industry reshuffling
US – Memphis considers exiting TVA supply
Introduction
Pipes & Wires has been examining what
appears to be an increasing trend of municipalities wanting to take control of
their own electric supply through such means as buying out private electric
companies or exiting wholesale energy supply arrangements, ostensibly to reduce
prices and reduce CO2 emissions. This article examines recent moves
in the US city Memphis, Tennessee.
Recent
events in Memphis
Memphis
Light, Gas & Water (MLGW) supplies 431,000
electric customers throughout Memphis and Shelby County, and currently receives
all of its electricity from the Tennessee Valley Authority (TVA)
for which it pays about $1b per year.
A report by Siemens suggests that MLGW
could save between $120m and $150m per year by sourcing its energy from a
combination of the Midcontinent ISO and developing its own renewables. This
would require MLGW to build at least some transmission lines, and could result
in some loss of supply reliability (which doesn’t seem to get a lot of attention
in comparison to price and CO2 emissions).
Editors’ note - municipalisation is not new
to these guys, as the City Of Memphis purchased the local portion of Memphis
Power & Light in 1939 for $15m.
Recapping
the other municipalisations
A quick recap on the other
municipalisations that Pipes & Wires has covered include…
Municipality |
Current arrangement |
Proposed future arrangement |
PW ref. |
Memphis, TN |
Muni takes all energy supply from TVA. |
Muni takes supply from a combination of
MISO and builds own generation. |
PW #199 |
Pueblo, CO |
Assets owned and energy supplied by Black
Hills Energy. |
Exit Black Hill supply arrangement as
provided for, acquire assets at a cost of around $900m to $1b, operate as a
division of Water Works (Proposal rejected by voters). |
|
San Francisco, CA San Jose, CA |
Distribution assets owned by Pacific Gas
& Electric, energy supplied by City itself. |
Acquire PG&E assets, operate as a
Muni |
|
Chicago, IL |
Assets owned and energy supplied by
Commonwealth Edison, with franchise payment to City. |
Acquire the CommEd assets within the
City, and operate as a Muni. |
|
Boulder, CO |
Assets owned and energy supplied by Xcel
Energy. |
Purchase Xcel assets and operate as a
Muni. |
Pipes
& Wires will reexamine Memphis’ plans as news emerges.
Energy mix and grid security
Aus –
re-examining the gas exploration moratoria
Introduction
Pipes
& Wires #162 took a broad look
at gas supply on the east coast of Australia, and particularly noted the
state-by-state moratoria on new gas exploration. This article re-visits those
moratoria and comments on how they might affect Australia’s security of gas
supply.
Recent
events in each state
The recent events in each state are as
follows…
State |
Previous moratoria |
Recent events |
Victoria |
Announced a permanent ban on all
unconventional on-shore gas development (including fracking and coal seam gas
exploration) on 30th August 2016, and a moratorium on any other
on-shore gas exploration until 30th June 2020. |
Passing of the Petroleum
Legislation Amendment Bill 2020 will
allow the restarting of conventional on-shore gas exploration. |
Tasmania |
Extended the 1 year moratorium on
fracking introduced in March 2014 by a further 5 years until March 2020. |
Fracking ban was reconfirmed in October
2018, and will remain in place until 2025. |
Northern Territory |
Moratorium on fracking introduced
in September 2016 for an undefined period. |
Focus of recently established Economic
Reconstruction Commission will include
“securing long-term domestic gas supply”. The
state government will also support gas explorers to innovate and adapt to new
market conditions. |
South Australia |
Proposing a 10 year moratorium on
unconventional gas exploration if the Liberals are elected in 2018. |
Some efforts in late 2019 to overturn
fracking ban. |
New South Wales |
the Gas
Plan
attempts to provide a strengthened regulatory framework for ensuring that
water purity and customer prices are well managed, however it is unclear how
new exploration and development will be incentivised. |
The Petroleum
(Onshore) Amendment (Coal Seam Gas Moratorium) Bill 2019 which
sought to immediately curtail prospecting or extracting of coal seam gas was defeated
in the Lower House, surprisingly
after it had passed in the Upper House. |
Western Australia |
On-shore fracking was banned
in September 2017. |
The on-shore fracking ban was lifted in
November 2018. |
The
editor comments on security of energy supply
It is acknowledged that the headline possibility
of “more gas” will not sit easily with some, however future restrictions on gas
supply strikes right at the heart of the third and often overlooked dimension
of the energy trilemma … security of supply. Careful thought will be required
if Australia wants gas to play a significant role in the transition to
renewables.
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.
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, nor from any
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