From the
editor’s desk…
Welcome
to Pipes & Wires #168. A lot seems to have happened in the United States at
both State and Federal levels over the last month or so with tariff
restructuring and paying for grid support and reliability, so this issue does
have a dominant focus on the USA.
This
issue also examines three network access decisions … two electricity
transmission decisions in Australia and a gas distribution decision in Ireland.
So … until next month, happy reading…
Recent client projects
Recent
client projects include…
· 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.
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Electricity markets & grid security
US – changing the business model
Introduction
Increasing
penetration of embedded generation has the potential to disrupt the traditional
regulated kWh-based business model. This article examines recent regulatory
changes in the US state of Illinois that could both encourage uptake of embedded
generation and minimise disruption.
The regulatory framework
The
regulatory framework is based on the Future Energy Jobs
Act which began life as Senate Bill 2814 which amends inter
alia the Public Utilities Act. Key features of the Act include…
· Allocating $140m per year for the purchase of renewable
energy credits to support new wind and solar projects.
· Allowing electric companies to treat rebates paid to solar
owners as virtual regulatory assets that are tariff-based and earn a guaranteed
return. This will lessen the impact of stranding traditional network
investments.
· Amends the Renewable Energy Portfolio Standard to ensure stable and predictable funding for wind and solar
projects.
The new business models going forward
The
underlying premise of the new business model is that electric companies will
become distribution system platform providers which neutrally manage multi-directional
power flows and oversee ultimately reliability (a bit like what transmission
grids have become).
The
important asset strategy issue is that an open-access network is likely to have
the same capital costs and probably higher operational costs than a
conventional uni-directional network, so one way or another whatever the
revenue model ends up as, it will need to provide at least as much cash as the
current kWh-based model. It appears that the provisions of the Future Energy
Jobs Act will provide for those new business models.
Embracing the “utility of the future”
Utility
Consultants in conjunction with the UMS Group have advised several electric
companies on “the utility of the future”. For more information pick here to contact Jeff Cummings from the UMS Group.
US – correctly paying for third-party demand response
Introduction
Instantaneous
matching of generation to demand has partially migrated from supply-side to
demand-side. Emerging technologies hold
the promise of further migration, but with the added twist of third-party
provision. This article examines the difficulty of correctly paying for
third-party demand response (DR) using recent events in California as a
starting point.
A bit about demand response
Historically,
instantaneous matching of generation to demand has included…
· Spinning reserve, in which specific hydro generators are
synchronised to the grid but operate at no load (so they can quickly pick load
if another generator trips).
· Load-shedding, in which load control relays are used to
disconnect load when the grid frequency drops to specified levels.
The
improved response time (from minutes for the old motor-generator injection
plant to milli-seconds for electronic injection and smart meters) and the
willingness of customers to be interrupted for short periods has obviously made
demand side more attractive than supply side which requires an expensive hydro
plant to not generate. There are 3 useful angles to examine demand response from…
· The simple technology issue (outlined above).
· The entry of third-party demand response provides into an
arrangement that was historically provided by only the electric company or its
customers.
· The basis of quantifying and paying for third-party DR.
Ensuring that third-party DR is correctly paid
During
California’s recent heatwave, two energy storage providers successfully offered
aggregations of automated load shedding into the wholesale market (which is in
accordance with the Cal ISO’s rules).
A key
issue to emerge is that the valuation of and hence payment for demand response
(DR) depends heavily on how much load was reduced (referred to as the
counterfactual, and like most arguments involving a counterfactual, we don’t
know for sure what that counterfactual really was).
However
the Cal ISO’s approach dates from 2010 when there wasn’t much DR on the grid.
Its’ current approach to quantifying DR is to compare the post-DR load to what
the load was in the previous 10 days which could understandably under-quantify
the DR if the previous 10 days had been cooler. One of the DR providers’ claims
that using this approach has led to only being paid for 53% of the DR it
provided.
Improving the DR payment approach
The
Cal ISO recognised that the maturing state of DR (in part driven by new
technologies that allow third-party participation) requires a new settlement
method. Improvements are being developed by the big electric companies, so
Pipes & Wires will comment further as news emerges.
The editor comments
The
transition from a traditional uni-directional, regulated network business model
to an open-access, multi-directional model in which the electric company
provides coordination and reliability will require thoughtfully developed
measurement and payment methods to provide certainty of investment for
third-party participants and certainty of cost recovery for the electric
companies.
US – who pays for grid
reliability services ?
Introduction
The recently released DOE report on markets and
reliability (refer to Pipes & Wires #167) concluded inter alia that market mechanisms need to be developed for paying
generators that provide grid reliability, resilience and buffering. This
article looks at the FERC’s response to that recommendation.
Issues raised in the recent DOE
report
The DOE report notes that “market mechanisms
are designed to incentivise individual resources rather than develop balanced
portfolios. System operators are working towards recognising, defining and
compensating for reliability and resilience-enhancing resource attributes … but
more work must be done” ie. there needs to be improved
market mechanisms for paying generators that provide frequency keeping,
controllable generation, peak capacity etc. Readers might’ve recalled that
getting properly paid for the electricity services provided by controllable
generation was one of the building blocks of the Nuclear Promise (refer to Pipes & Wires #157).
The FERC’s views
Initial comments from FERC Chairman Neil Chatterjee include the views that…
·
Coal-fired generators should be properly
compensated to recognise the value they provide to the system.
·
That provision of grid reliability might be better
implemented by making grid reliability features a
requirement for connection rather than through a market mechanism.
The most obvious implication of the second point
above is that wind and solar will need to contribute to grid stability if they
want to grid connect. Pipes & Wires will comment further as the FERC’s
thinking evolves.
US – recovering the costs of baseload generation
Introduction
Recovering
the full costs of (traditionally understood) coal and nuclear baseload
generation as they are displaced from the market by wind, solar and cheap gas
has been a thorny issue in many jurisdictions. This article examines the
Department of Energy’s (DOE) recent proposal for better recovery of baseload
generation costs, and follows on from the previous article on paying for grid
reliability.
The DOE’s proposal and its context
The
DOE has recently filed a Notice of Proposed Rulemaking (NOPR) directing the Federal Energy Regulatory Commission
(FERC) to “accurately price generation resources necessary to maintain
reliability and resiliency”. The context to the NOPR is the recent DOE study on
markets and reliability ordered by Secretary of
Energy Rick Perry (refer to Pipes & Wires #163 and #167).
The regulatory framework
The
regulatory framework includes…
· s403 of the Department of Energy Organisation Act, which provides for the DOE to propose inter alia rules with respect to any function under the FERC’s
jurisdiction.
· ss205 and 206 of the Federal Power Act, which broadly provides for the FERC to establish just and
reasonable rates (tariffs).
Key requirements for generators to be eligible
Key
requirements for a generator to be eligible for full cost recovery under the
NOPR are to…
· Have 90 days of fuel on-site.
· Be able to provide ancillary services as well as reliability
services.
· Comply with environmental regulations.
· Not already be subject to a cost-of-service recovery by a
State.
The wider context of cost recovery
Pipes
& Wires #157 noted that the 2nd of the 4 building blocks set out
in the Nuclear Promise’s strategic plan is “leverage federal and state policies
to ensure monetary recognition of nuclear energy’s value”, for which one of the
specific actions is to reform capacity markets by developing market mechanisms
that value the attributes of nuclear power plants. So it looks like the nuclear
industry might get its wish on this one (and whether it ends up as a market or
regulated solution remains to be seen).
Post-script
The
NOPR seems to have lit a fire in Washington, with FERC pushing back in defence
of existing market structures.
Tariffs & pricing
US – regulatory support for embedded generation tariffs
Introduction
Suppliers
and lobby groups alike have vigorously opposed any requirements for rooftop
solar customers to pay higher prices. This article examines a recent regulatory
decision in the US state of Kansas that may allow electric companies to
establish separate prices or tariff classes for customers with embedded
generation to limit the need for subsidies from other customers.
Background to the KCC’s decision
In
July 2016 the Kansas Corporation Commission (KCC) opened a General
Investigation to examine various issues around prices and tariff structures for
embedded generation which was expected to include an assessment of the
quantifiable costs and benefits of embedded generation. All the electric
companies under the KCC’s jurisdiction were named as parties to the General
Investigation, allowing them the opportunity to submit evidence.
The legal standard
Key
features of the legal standards are inter
alia as follows…
· Every public utility in Kansas is required to … establish
just and reasonable rates (prices).
· Just and reasonable rates are those that fall within a zone
of “reasonableness” which balances the interests of present and future
ratepayers (customers), and the public interest.
· The Kansas Supreme Court has recognised that the touchstone
of public utility law is that rule that one class of consumers shall not be
burdened with costs created by another class.
The KCC’s decision
In
September 2017 the KCC concluded inter alia that…
· Electric companies may establish a separate rate (tariff)
class and propose new rate design (pricing methodologies) for embedded
generation customers to ensure that those customers share in the fixed costs of
the electric grid and are not subsidised by other ratepayers (customers).
· Customers who install embedded generation prior to new
tariffs taking effect will be allowed to remain on the existing tariff until
2030.
Responses from the various sides to the issue
Responses
to the KCC’s decision are understandably mixed…
· Electric companies seem happy that they can minimise
subsidies and equitably recover costs.
· Customer advocates and solar lobby groups are disappointed
with the KCC’s decision. This tends to reinforce the sad conclusion that solar
owners somehow expect to free-ride the network.
US – rebalancing the fixed and variable tariffs
Introduction
Opposition
to increasing the fixed component of electric tariffs is nothing new …
promoters of rooftop solar have claimed that increasing the fixed tariff
component (whilst also reducing the variable component) undermines the benefits
of solar. This article examines recent plans to rebalance tariffs in the US
state of Nevada in response to the new nett metering law.
Background
Electric
distribution companies have a high ratio of fixed to variable costs, but
historically have recovered most of those fixed costs through variable (kWh)
tariffs. That was all fine as long as customers kept on consuming similar
annual kWh’s, but the advent of rooftop solar has
eroded those kWh volumes and with it the recovery of fixed costs that over time
will under-fund the distribution business.
The
most obvious alternative is to re-balance the mix of fixed and variable tariffs
to make the revenue less dependent on kWh consumption. This has two economic
consequences…
· In the short term it makes rooftop solar less beneficial by
reducing the avoided costs of imported kWh and increasing the unavoidable
monthly fixed charge (and as far as I know, electric companies have never denied
this).
· In the long term it increases the incentive to go off-grid
and avoid the fixed monthly tariff (the death spiral).
Nevada’s nett metering law
Assembly Bill 405 was introduced to the Nevada Legislature in March 2017 with
the aim of…
· Protecting customers who use renewable energy.
· Revising provisions for nett metering.
A key
feature of the Bill was that it restored nett metering rates to 95% of the
retail rate. The Bill was signed into law in June 2017 by Governor Brian
Sandoval.
NV Energy’s proposed tariff rebalancing
Key
features of NV Energy’s proposed tariff rebalancing include…
· Increasing the fixed monthly tariff from $12.75 to $16.76,
but noting that customer bills should remain about the same because of a
corresponding reduction in the kWh tariff.
· Paying rooftop solar customers 95% of the prevailing import
rate for their exported energy. This will decline by 7% for every 80MW of
rooftop solar installed until a floor of 75% is reached.
The Nevada PUC’s response
The
PUC’s response was awaited at the time of publication, so Pipes & Wires
will pick up this story again in the future.
Network access decisions
Aus – the TransGrid revenue determination
Introduction
The Australian
Energy Regulator (AER) recently published its Draft Decision for TransGrid for the five year period beginning on 1st July
2018. This article examines the key features of that Draft Decision.
A bit about TransGrid
TransGrid
owns and operates 13,000km of lines at 500kV, 330kV, 220kV and 132kV that
supply 99 bulk supply substations (GXP’s). Following the completion of the 99
year lease process in 2015, TransGrid is owned by a consortium led by Hastings Funds Management.
Regulatory framework
The
basis of the regulatory framework is Chapter 6a of the National Electricity Rules, which is made pursuant to the National Electricity Law.
Key features of the process
Key
features of the process to date include…
|
Parameter |
Initial
Proposal |
Draft
Decision |
Revised
Proposal |
Final
Decision |
|
CapEx |
$1,612m |
$992m |
|
|
|
OpEx |
$908m |
$941m |
|
|
|
Opening
RAB |
$6,406m |
$6,373m |
|
|
|
WACC |
6.6% |
6.5% |
|
|
|
Regulatory
depreciation |
$678m |
$631m |
|
|
|
Smoothed
revenue |
$3,973m |
$3,910m |
|
|
Next steps
The
next step is for TransGrid to submit its Revised Proposal, after which Pipes
& Wires will comment further.
Ireland – setting the gas distribution revenue
Introduction
After
examining a whole bunch of Australian gas pipeline tariffs in PW #167, we now
move half a world away to take a quick look at a recent gas distribution revenue
decision in Ireland. This article examines the PC4 gas distribution revenue decision which applies to Gas Networks Ireland’s distribution
business for the 5 year period starting on 1st October 2017.
A bit about Gas Networks Ireland
Gas
Networks Ireland owns 2,200km of transmission pipelines and 11,200km of distribution pipelines throughout Northern Ireland and the Republic of Ireland
that supply 674,000 end-use customers. Bulk supply is taken from 3 undersea
pipelines from Scotland.
GNI is
the residual business after the sale of the Bord Gáis Éireann supply business
to Centrica in 2014, and is part of the statutory corporation Ervia.
The regulatory framework
A key
feature of the regulatory framework is Section 10 of the Gas Act 1976, which limits the revenue to all charges properly
chargeable to revenue and a reasonable return on the capital it employs.
Key features of the PC4 decision
Key
features of the PC4 decision include…
|
Parameter |
Sought
by GNI |
CER
decision |
|
CapEx |
529m |
332m |
|
OpEx |
377m |
340m |
|
WACC |
4.96% |
4.63% |
|
Revenue |
1,123m |
990m |
Aus – the Murraylink revenue determination
Introduction
The Australian
Energy Regulator (AER) recently published its Draft Decision for the Murraylink for the five year period beginning on 1st July
2018. This article examines the key features of the Draft Decision.
A bit about the Murraylink
The
Murraylink is a 180km long HVDC cable link between Berri (South Australia) and
Red Cliffs (Victoria) which operates at 150kV and has a rating of 220MW. It was
built by TransEnergie Australia and commissioned in 2002, and is now owned by
Energy Infrastructure Investments Pty Ltd.
Regulatory framework
The
basis of the regulatory framework is Chapter 6a of the National Electricity Rules, which is made pursuant to the National Electricity Law.
Key features of the process
Key
features of the process to date include…
|
Parameter |
Initial
Proposal |
Draft
Decision |
Revised
Proposal |
Final
Decision |
|
CapEx |
$34m |
$27m |
|
|
|
OpEx |
$22m |
$24m |
|
|
|
Opening
RAB |
$114m |
$114m |
|
|
|
Nominal
vanilla WACC |
6.54% |
5.7% |
|
|
|
Regulatory
depreciation |
$27m |
$23m |
|
|
|
Smoothed
revenue |
$96m |
$85m |
|
|
Next steps
The
next step is for Murraylink to submit its Revised Proposal, after which Pipes
& Wires will comment further.
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.
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 and are not intended as specific legal, consulting or
investment advice, and are correct at the time of writing. In particular Pipes
& Wires may make forward looking or speculative statements, projections or
estimates of such matters as industry structural changes, merger outcomes or
regulatory determinations. These articles also summarise lengthy documents, and it is important that readers refer to those
documents in forming opinions or taking action.
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Consultants Ltd accepts no liability for action or inaction based on the
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