From the
editor’s desk…
Welcome
to Pipes & Wires #119. This month we start by examining some critical asset
management issues, and then move on to some regulatory developments in the NZ
gas pipes sector. We look at water pricing in the UK, paying for standby
generation in Germany and easing electricity regulatory pressure in the UK. We
then take a quick look at a regulatory decision in Australia and conclude with
some storm recovery and smart grid happenings in the US.
General stuff
Consulting services that may be of
interest to clients
Utility
Consultants wide expertise extends well beyond the above projects ... if you
need energy network advice chances are Utility Consultants has done work in
that area. Here’s a sample of work done for clients over the last few years
that demonstrate the breadth of skills, insight and experience that is
available....
·
Advised an electricity business on the
regulatory implications of bringing externally contracted field services back
in-house.
·
Identified economic and regulatory
arguments to support inclusion of transmission interconnection charge risk into
network tariffs.
·
Advised lines businesses on a
regulator’s proposed treatment of CapEx and OpEx.
·
Advised an international investor on
gas distribution policy and regulatory trends.
·
Identified national energy policy
implications for lines businesses.
·
Assisted a lines business to identify
the burden of proof implied by regulatory determinations.
·
Suggested amendments to a gas
transmission AMP to strengthen the economic arguments.
·
Identified electricity network
investment characteristics as part of an acquisition study.
·
Developed an AM framework for a gas
distribution business to link AM to regulatory requirements.
·
Identified OpEx – CapEx tradeoffs for an electricity lines
business.
·
Performed various substation growth and
reinforcement assessments.
·
Performed network physical and business
risk studies.
·
Compiled disaster recovery and business
continuity plans.
Pick
here
to download a profile of recent projects, or here
to contact Phil.
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.
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.
Conferences & training courses
The following
conferences and training courses are planned...
· Electricity
Industry Fundamentals – Wellington, 18th – 19th March
2013.
· ACCC / AER
Regulatory Conference – Brisbane, 25th – 26th July
2013.
· Infrastructure, Investment &
Regulation Conference – Sydney, 30th – 31st May 2013.
· CIGRE
International Symposium – Auckland, 16th – 17th
September 2013.
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…
·
Wonders Of World Engineering
(published 1937) – in particular editions 1 to 27.
·
White Diamonds North.
·
Northwards March The Pylons.
·
Two Per Mile.
·
Live Lines (the old ESAA journal).
·
The Engineering History Of Electric Supply In New Zealand.
Global
Optimising
asset management
Introduction
As I
work with many electric companies and read a lot of articles and listen to a
few podcasts, it seems that asset management in the electricity sector (and
indeed in other infrastructure sectors) seems to be facing a few common frontiers.
These frontiers appear to be...
Increased regulatory scrutiny of CapEx
Recent
years have seen significant uplifts in forecast CapEx, both from aging assets requiring renewal and to restore capacity
and security headroom. In the case of transmission grids and pipelines, the CapEx is also usually lumpy ie. consists
of a small number of large projects.
In
many (but certainly not all) cases those forecasts have been significantly
reduced in the regulators’ draft and final decisions. I’m getting a sense that
some regulators are not fully comfortable with such significant forecast
uplifts and seem to be placing undue emphasis on previous regulatory periods
(noting that some jurisdictions require the regulator to “have regard” to the
forecasts from previous periods).
Interfacing detail design with physical
works delivery
Most
infrastructure companies seem very good at detail design, and also seem to have
a good handle on physical delivery of the works. The fuzzy activity between the
two ... often called “project planning” or “works delivery” seems to be the
uneasy bedfellow, and yet it also seems to be the most critical activity along
the project delivery chain.
I’ve
observed this “works delivery” activity being embodied within engineering
design, standing alone as a third party, being attached to the construction
function, being out-sourced to contractors, and being attached to the end of
asset management. Probably the best model appears to be a specialist works
delivery function at the tail of the asset management activity, giving a high
degree of control to the client rather than the contractor and ensuring a close
but none-the-less delineated relationship with asset management and detail
design.
Improved asset condition data to
support renewal modeling
As
noted above, regulators seem uncomfortable with the significant uplifts in
renewal CapEx being proposed by many infrastructure companies. Asset
condition is obviously a key driver of renewal spend, but as most of us know,
determining the precise condition (and hence remaining life) of a sealed or
buried asset is difficult at best. Despite an increasing number of
sophisticated scientific tests available for determining asset condition I’m
not sure that we are getting close to accurate answers that will in turn lead
to absolutely defensible renewal profiles.
Perhaps
another angle on this is to consider asset criticality (and I know many are
doing this already), and make a judgment call that for critical assets it is
better discard some unconsumed asset life rather than risk an in-service
failure and possible health and safety consequences.
To
discuss these issues further, pick here
or call Phil on +64-7-8546541
New Zealand
NZ – disclosure of gas AMP’s
Introduction
Electricity
distribution businesses (EDB’s) have had to publically disclose an asset
management plan (AMP) since March 2000, with several revisions to the
requirements that embody some themes (ask
me about this). Much more recently, the Commerce
Commission’s decisions NZCC 23 and NZCC
24 set out the requirements for gas distribution and gas transmission
businesses (collectively referred to as gas pipeline businesses, GPB’s) to disclose
an AMP that meets specified criteria.
Legal framework
The
legal framework for an information disclosure regime is set out in Subpart
4 of Part 4 of the Commerce
Act 1986. Subpart 10 of Part 4 (s55c) provides for all gas pipeline
services to be subject to information disclosure.
AMP disclosure requirements
The
specific disclosure requirements for both gas distribution and gas transmission
are set out as follows...
·
Section 2.6 of each decision sets out
the various broad requirements that an AMP must meet, such as contributing to
the Part
4 Purpose Statement, and being able to be understood by someone with a
basic knowledge of infrastructural asset management.
·
Section 2.6 sets out the dates by which
each GPB must disclose its’ AMP. Care is required, as the dates are based on
several defined terms that much be well understood.
·
Section 2.6 also describes the various
forecasts (Schedules 11a to 12b that include CapEx, OpEx, asset condition and demand).
·
Attachment A sets out the specific
clause-by-clause requirements that the AMP must include.
·
The asset management maturity
assessment tool (AMMAT) in Schedule 13 must also be completed and disclosed.
These
requirements are almost identical to the disclosure requirements for
electricity AMP’s.
Next steps
Utility
Consultants has advised 11 EDB’s on their AMMAT obligations and 22 EDB’s on
their AMP obligations, and is therefore well placed to advise GPB’s on their
AMP’s and AMMAT’s. Pick here
or call Phil on (07) 854-6541 to discuss your requirements.
NZ – cost of capital for the Maui
Pipeline
Introduction
Recent
issues of Pipes & Wires have examined the weighted average cost of capital
(WACC) that will apply to various gas distribution and transmission businesses
(Pipes
& Wires #116 and #118).
This article examines the Commerce Commission’s recent WACC
Determination that will apply to Maui Developments Ltd for the 2014
Disclosure Year (which commences on 1st January 2013).
What exactly does Maui do ?
In
addition to owning the Maui
Pipeline, Maui Developments also performs 3 operator roles...
·
Technical and engineering operation of
the actual pipeline.
·
Commercial operation of various
contracts and regulatory requirements specific to the pipeline.
·
System operator functions such as
balancing, reconciliation, coordination and contingency management.
Legal framework
The
WACC determinations have been made pursuant to Subpart 4 of Part 2 of the Gas
Transmission Services Input Methodologies Determination 2012, which has in
turn been compiled pursuant to Subpart
3 of Part 4 of the Commerce
Act 1986.
The determination
The Commission
has determined that the following WACC’s will apply for the 5 year period
commencing on 1st January 2013...
|
WACC
definition |
Mid-point WACC
value |
25th
percentile |
75th
percentile |
|
Vanilla |
6.65% |
5.84% |
7.46% |
|
Post-tax |
5.99% |
5.18% |
6.80% |
UK and
Europe
UK – compiling the next water price
control
Introduction
The
UK water and sewage regulatory OFWAT
has started compiling the price controls that will apply for the 2015 – 2020
control period, which forms the subject of this article. This follows on from
OFWAT’s analysis of some very significant issues (Pipes
& Wires #110).
OFWAT’s statement of principles
OFWAT
acknowledges that since setting the last price limits in 2009 the UK’s water
sector has changed significantly hence it was necessary to undertake a review
of regulation that was both wide and deep. This review incorporated the
findings of several other independent reviews into detail aspects of the water
sector.
This
has resulted in several “price
limit principles” being promulgated...
·
Targeting price control appropriately,
including using different regulatory tools for different parts of the business
and reducing or removing regulation where it becomes unnecessary.
·
Using a risk-based approach to
compliance to reduce regulatory burden.
·
Developing clearer incentives that
better drive economic efficiency.
·
Setting price controls that make
companies more accountable for delivering customer needs.
·
Designing regulatory tools that are
flexible and responsive.
·
Ensuring that regulation is transparent
and predictable.
OFWAT’s proposed framework
Probably
the most significant feature of OFWAT’s proposed
framework is a visible separation of the controls that will apply to the
wholesale water activities and the retail water activities, ostensibly forcing
water and sewage businesses to better understand and respond to the
price-quality trade-offs that customers want. Other features of the framework
include setting default tariffs and service levels, and examination of total
costs.
Next steps
OFWAT
is receiving submissions on the proposed framework until 26th March
2013, with a final decision on the methodology expected about mid-2013.
Germany – who should pay for standby
generation, and how ?
Introduction
Debate
is increasing in Germany over who should pay for standby generation, and exactly
what the payment mechanism should be. This article considers 2 contrasting
viewpoints, and also touches on the complexity of national v’s regional
solutions.
The key issues
Standby
generation is being increasingly used to buffer intermittent wind power, so the
GWh generated by the standby plants are declining. To pick on an example quoted
in the media, the 800MW
Knapsack #1 gas-fired plant near Cologne generated only 1,000GWh during
2012, down from 3,000GWh in 2011 and much less than its full capacity of
6,000GWh per year. The key issues are...
·
The basis for payment is still MWh, not
peak MW.
·
There is a political desire for security
of supply, albeit a desire that seems disconnected from the obvious question of
“who pays for the security”.
The contrasting viewpoints
Just
2 contrasting viewpoints include...
·
Statkraft (the owner of Knapsack #1) is calling for a capacity
payment of €15 per kW per year that should apply to all gas-fired plants (so
Knapsack would receive about €12m per year). Statkraft argues this is less than 10% of the annual cost of
“supporting” renewables.
·
E.On on the other hand has expressed concerns about capacity
payments being based on national solutions, stating that capacity payments
should be a last resort, be a harmonised
EU-wide initiative, shouldn’t favor specific generation technologies and
shouldn’t exclude any market participants.
So
on the one hand we have a very pragmatic, fix-the-problem-now argument and on
the other hand a seemingly theoretical and multi-pronged argument. Both
arguments would appear to embody at least some self-interest.
The national v’s regional debate
Much
has been made of harmonising the EU’s energy markets, so E.On’s
view that any capacity payment mechanism needs to be consistent across the
entire EU and not Germany makes some sense. However does that over-ride the
need to fix a specific problem in Germany ?
The editor comments
As I
see it there are several issues...
·
The seemingly huge disconnect between
the “must have” security of supply and the need for standby generators to be
paid for providing that security of supply.
·
The lack of clear progress on embedding
payment mechanisms in electricity markets that reflect parameters other than
short-run MWh.
·
The unwillingness to fix a national
problem because we must fix it at a regional level.
·
The lingering distinction between
subsidies paid to fossil-fired generators (bad) and the subsidies paid to renewables (okay).
So
... how’s this for a possible solution ? The principle
of “exacerbater pays” is being considered by transmission grid companies ...
if a connected party causes costs, they pay. Why not apply a similar approach
to renewable generators ? Send a cost signal that
provides an economic basis for either the renewable generator to reduce their
impact on power fluctuations, or pays a third party to provide standby
generation. After all we do this quite successfully for other issues like poor
factor or transmission congestion.
UK – reducing regulation of competitive
activities
Introduction
A
key principle of regulation is that only activities that are not subject to
competitive pressures should be regulated ... the UK water regulator OFWAT has recognised this in its framework for the 2015 – 2020 water and sewage
price controls. This article uses OFGEM’s
proposed lifting of price regulation for Scottish
& Southern Energy’s new connection business as a starting point, but
then expands into a wider discussion of when regulation should be applied.
OFGEM’s proposal
OFGEM
has been working to facilitate competition in the new network connections
market for about 12 years in the belief that competition is more likely to
promote innovation, lower prices and customer choice than regulation would.
However progress was slow until the 5th price control (EDPCR5)
provided for a 4% margin on contestable services, giving new entrant provides
something to capture.
EDPCR5
also provided for regulated electric companies to seek a lifting of price
regulation in markets where they believe effective competition exists. OFGEM
seems sufficiently satisfied that effective competition exists in the market
for new network connections to propose lifting regulation.
Some wider issues
Some
of the wider issues to be considered include....
·
The recognition (including by
regulators) that effective competition will generally always result in superior
levels of innovation, price-quality trade-offs and customer service than
regulation.
·
The need for small pieces of ostensibly
monopolistic networks that are subject to competition to be excluded from the
regulatory regime. That obviously poses some challenges for a regulator,
particularly when the wider regulatory regime states something like “all direct
control services provided by XYZ Electric Company will be subject to price
control” that doesn’t appear to anticipate exempting small pieces of the assets.
·
The need for the benefits of regulation
to outweigh the costs. If I recall rightly, the New Zealand Gas
Inquiry all those years ago concluded that although some gas companies
should’ve been subject to price control the cost of doing so would’ve exceeded
the benefits to customers. Very refreshing thinking.
So ... worth a few moments thought, eh.
Australia
Aus – the Murraylink Revised Proposal
Introduction
Readers
might remember that about 10 years ago the Murraylink HVDC converted from a market-based service to a regulated
network service. This article examines the Murraylink’s Revised Proposal for the 1st July 2013 – 30th
June 2023 regulatory period.
What exactly is the Murraylink ?
Murraylink is a 180km long, 150kV, 220MW HVDC link between Red Cliffs,
Victoria and Berri, South Australia. The technology is Insulated
Gate Bipolar Transistors (IGBT’s) and perhaps even more uniquely the entire
line route is by underground cable.
The
link was originally built by Hydro Quebec
subsidiary TransEnergie Australia but was sold to the APA Group in March 2006.
Key aspects of the revised proposal
Key
parameters of the decision process to date include...
|
Parameter |
Original
Proposal |
Draft Decision |
Revised
Proposal |
Final Decision |
|
Opening
RAB |
$102.4m |
$107.1m |
$107.63m |
|
|
Nominal
Vanilla WACC |
8.61% |
7.11% |
7.11% |
|
|
CapEx – first 5 years |
$13.8m |
$7.3m |
$6.3m |
|
|
Nominal OpEx – first 5 years |
$40.1m |
$34.1m |
$21.2m |
|
Pipes
& Wires will comment further once the Final Decision is released.
North America
US – power to the people
?
Introduction
News
emerged recently that New York Governor
Andrew Cuomo wants more power over “under-performing utilities”. This
article tries to get to the bottom of exactly what Cuomo might be angling for,
and presents a few opinions on those matters.
What exactly has Cuomo said ?
A
few of Cuomo’s salient comments include...
·
“Progress (at restoration) is
occurring, but that progress is unacceptable”.
·
“Utility companies have not performed
adequately ... they have been told that repeatedly”.
·
“They will be held accountable for
their lack of performance”.
·
“Yes, it was a catastrophic storm, but
they should’ve been prepared, they should’ve been responsive”.
What might Cuomo be angling for ?
Cuomo
is certainly hopping mad, but what might he really be angling for ? The unworthy cynic might well say he is simply tapping
a rich vein of voter anger to perpetuate his own political fortunes by targeting
the ever-unpopular monopoly businesses, whilst on the other hand at least some
customers will probably go along with Cuomo.
There
is talk of giving state regulators further powers, such as being “able to
terminate the relationship” (presumably through the cancellation of a license,
which can theoretically occur in many other jurisdictions).
What might actually occur
?
Well
... it’s a bit hard to know what exactly might occur. But here’s
a few thoughts...
·
My understanding is that recent
regulatory policy in New York has shown a bias towards smart grids, with
proposed funding for network hardening being rejected by the NY Public Service Commission. Not
surprisingly, smart grids proved to be of little use under salt water.
·
Are there other, less draconian,
regulatory sanctions (or even perhaps mechanisms that already exist within the
regulatory framework) that discourage poor storm response whilst avoiding
investment uncertainty.
·
What about some carrots to go with the sticks ? Something like allowing extra regulated revenue for
increased responsiveness ?
·
What might the threat of license
termination actually look like ? Would it
require a forced sale of assets to the City or State at a non-negotiated price for
them to run as a Muni ? My guess is that for starters that would increase investment
uncertainty, pushing up the cost of capital which would need to be reflected in
higher tariffs.
·
Would a competitive business that had
the bulk of its means of production fully vulnerable to a catastrophic storm
have fared any better (a bit of academic argument, I know, but worth thinking
about).
·
How much storm protection is enough ? Apparently the bund at the E14th
Street substation was 12 feet high, but the incoming water was 14 feet
high. I would’ve thought 14 feet of water on the streets of Manhattan would
constitute unreasonable circumstances.
·
Some careful thought about the urgency
for supply restoration is needed. Many customers houses would have presumably still
been flooded or at least water damaged, so do we really want to reconnect the
electricity early in the play ?
US – more power to the people ?
Introduction
Relationships
between City or State government and investor owned utilities (IOU) can often
be tense, often founded on the assumption that a Muni’s tariffs would be lower
than an IOU’s tariffs. This article examines an emerging scrap between the City
of Boulder, Colorado and Xcel Energy
and tries to understand what the issues are and whether the proposed “Muni’ing” of Xcel’s
distribution assets might actually work.
Note
that this is a separate issue from the recent Colorado PUC ruling that Xcel’s Boulder SmartGridCity project hadn’t shown
sufficient benefits to justify Xcel recovering the remaining $16.6m of
costs.
The current electricity supply
arrangement in Boulder
The
original electricity supply in Boulder was from the Public Service Company of
Colorado (PSCo). Through a series of mergers, PSCo became Xcel Energy, which now supplies 3,400,000 electric and
1,900,000 gas customers across Colorado, Michigan, Minnesota, New Mexico, North
Dakota, South Dakota, Texas and Wisconsin. Annual revenues are about $10.7b.
Boulder
began researching alternative supply arrangements in 2005, and commissioned a
report which concluded that the City could feasibly purchase Xcel’s distribution assets and keep tariffs comparable to Xcel’s. These plans were shelved in 2008 when Xcel selected
Boulder for its SmartGridCity program.
The City of Boulder’s concerns
The
City has a stated suite of energy
goals, which include reducing CO2 emissions, providing customers
with a greater say about their energy and promoting social justice. It’s not
totally clear what the City’s precise concerns are but a quick read of some
topical media suggests that the City simply wants more renewable energy. I
suspect there is probably also some thinking along the lines that a Muni
wouldn’t need to make a profit, hence its tariffs could be lower.
The proposed Muni’ing – what might it involve
?
After
negotiations for the City to partner with Xcel to build a wind farm broke down
in July 2011 the City decided to put Muni’ing back on the voter
ballot. The City plans to vote on the issue in April, and the expectation
is that the vote will be in favor of purchasing Xcel’s distribution business and running it as a Muni.
Some issues to think about
A
few key issues that might need to be considered include....
·
The City’s cost estimate to establish
and run a Muni is $290m, a long way short of Xcel’s estimate of $1.2b.
·
The City plans to supply a lot more
renewable energy, and the evidence is that renewables are leading to rapid cost increases. In contrast, Xcel’s generation portfolio includes about 7,700MW of coal-fired
stations of which many are large and mature (and should therefore have low
costs per MWh).
·
A Muni will lack scale, certainly the
scale of a company the size of Xcel.
·
A Muni will be subject to municipal
interference, or perhaps to put it more politely, become an instrument of
policy (the City’s energy goals make that abundantly clear).
·
Whether the loss of scale (duplication
of management and board functions etc) and loss of access to low-cost coal
fired generation will off-set any reduction in tariffs from avoiding the IOU
model.
·
Presumably the City will have to use
real $$$ to buy the distribution assets. Somewhere, somehow those funds will
have a capital charge. Whether the City makes them explicit on electric
accounts or tries to bury them and quietly let Boulderites pay the capital charge through their property taxes remains
to be seen.
Pipes
& Wires will re-examine this in a few months once the City’s vote has
occurred.
US – recovering the cost of smart grids
Introduction
Most
jurisdictions require some form of regulatory approval to recover costs through
regulated tariffs. Investment certainty is improved when this approval is
ex-ante, and correspondingly declines when approval can be ex-post ie. the regulatory can disallow recovery after implementation. This
article examines the Colorado
Public Utility Commission’s (PUC) decision to prevent Xcel Energy subsidiary
Public Service Company of Colorado (PSCo) from
recovering the final $16.6m of costs of the Boulder SmartGridCity program.
What exactly is
SmartGridCity ?
SmartGridCity is technology pilot program that Xcel Energy is rolling out
in the City of Boulder, Colorado. The heart of the program appears to be a
roll-out of 23,000 smart meters to determine customer preferences for energy
management tools, provide web access to accounts to facilitate energy
conservation and demand management, and detect outages.
What seems to have gone wrong ?
It
seems that the following things have gone wrong...
·
SmartGridCity was
originally costed at $15.3m, but ended up costing something like $45m. It
appears that the hardness of the ground in Boulder for installing fiber was
significantly under-estimated.
·
Real time demand management is not
really possible. It appears that some smart kit was not actually installed.
·
An apparent under-estimate of just how
much demand reduction or energy conservation would actually occur in response
to signals such as text messages.
What was the PUC’s response
?
By March 2012, the PUC had approved recovery of $27.9m,
leaving $16.6m outstanding. Recovery of that outstanding $16.6m would require
Xcel to inter alia provide strong
evidence of customer and community engagement, better defining how customers
could make use of smart meters, and better defending its strategic plan.
In a decision
released in January 2013, the PUC denied Xcel recovery of the balance of the
capital costs. At the time of writing, Xcel had not decided whether to appeal
the PUC’s decision.
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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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