From the editor’s
desk…
Welcome
to Pipes & Wires #103. This article starts by examining a major re-think of
corporate strategy in Europe, and then reviews 4 regulatory decisions (well, okay
3 decisions and 1 proposal). We also catch up on a couple of mergers in the US
and examine some regulatory policy issues, including a bit of widening of scope
to look at the next UK rail price reset.
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Matters
for attention
NZ
– public safety management systems
Just a reminder that the requirement for
all electricity businesses (of more than 10MW capacity) to have their PSMS in
place and externally audited is only 8 months away. For help with compiling
your PSMS, or to have a pre-audit review undertaken, phone Phil on (07)
854-6541 or pick
here.
Corporate
strategy
Global
– revisiting E.On’s strategy
Introduction
Over the years Pipes & Wires has
examined German utility E.On’s “On Top”
strategy which set out a global growth plan based on 5 key geographical
platforms. On the back of recent reversals to that strategy, this article takes
a closer look at E.On’s much revised strategy.
The
original “On Top” strategy
The
core of the “On Top” strategy was to grow five well defined markets principally
through acquisition as follows…
Market |
Emphasis |
Platform |
Pan-European
gas transport and storage. |
Acquiring
privatised gas transmission utilities in the former Soviet-bloc. |
|
Central
European electricity market. |
Consolidation
of distribution and retail businesses. |
|
Scandinavian
electricity. |
Strengthening
market position through further acquisitions. |
|
UK
electricity. |
Strengthening
market position through acquisitions. |
Powergen |
US
mid-west electricity. |
Long-term
expansion. |
A
guiding principle of “On Top” is to systematically capture the synergies
implicit in all acquisitions and ensure those synergies are returned to
shareholders
Reversing
the strategy
For a long while it appeared that the
disciplined approach of “On Top” would safeguard E.On’s long-term future,
especially when compared to its most visible rival, Electricité
de France (EDF). However a few telling signs began to emerge ... re-thinks
on apparently sound acquisitions, and then divesting of grid assets such as LG&E – KU, Central Networks and Transpower
Stromübertragungs GmbH (and it is acknowledged that some asset sales were
regulatory concessions rather than strategic realignments).
The wider context
In
the wider context, other network businesses began to be sold or at least
packaged for sale ... EDF sold its UK distribution businesses, whilst RWE
packaged up its’ UHV grid RWE
Transportnetz Strom into a subsidiary called Amprion. Pipes
& Wires #88 hypothesised that this was
an emergence of a preference for selling lines and retaining energy.
The
current strategy
E.On had previously announced that it
wanted to raise €15b from asset sales by the end of 2013, and it now appears
that grids will be the key part of that asset sale strategy. From E.On’s
perspective grids represent a high CapEx spend requirement coupled with low
growth levels which would strengthen the case for migrating capital to
unregulated businesses. Having said that, grids and networks do offer
predictable, inflation proofed, returns that make them attractive to both
pension funds and municipalities (which wouldn’t ordinarily have ready access
to high-growth unregulated markets other than through investing in electric
utilities).
Possible
next moves
So ... what might E.On’s next move be ?? A
couple of possible thoughts spring to mind...
·
Sale
of minority (non-strategic) stakes in distribution networks where E.On cannot
extract synergies. E.On has many such stakes both in its home turf of Germany
and in the former communist states in eastern Europe.
·
Sale
of transmission grids that link E.On’s existing or potential future retail
markets with E.On’s low-cost coal-fired plants. These coal-fired plants may
have an even greater role to play as Germany’s nuclear stations are closed.
Pipes & Wires will check back on this
as various deals and announcements emerge.
Regulatory
decisions
Aus – the Queensland gas distribution
final decision
Introduction
Previous
issues of Pipes & Wires (#96,
#99
and #100)
have examined APT
Allgas’ proposed Access Arrangement for its’ Queensland gas network (which
also crosses into NSW) for the period 1st July 2011 to 30th
June 2016. This article concludes that examination with a summary of the Australian Energy Regulator’s (AER) Final
Decision.
Key aspects of the revised Access
Arrangement
Key
aspects of the process are set out in the following table...
Parameter |
Proposed AA |
Draft Decision |
Revised AA |
Final Decision |
Total
OpEx |
$110.12m (nominal) $102m (nominal 10/11) |
$93m (nominal 10/11) |
$115m (nominal) |
$107m (nominal) |
Total
CapEx |
$139.05m (nominal) $129m (nominal 10/11) |
$125m (nominal 10/11) |
$145m (nominal) |
$128.9m (nominal 10/11) |
Opening
capital base |
$421.6m (nominal) |
$424m (nominal) |
$424m (nominal) |
$427m (nominal) |
Closing
capital base |
$559.9m (nominal) |
$562m (nominal) |
$551m (nominal) |
$554m (nominal) |
Rate
of return |
10.3% (post-tax nominal vanilla) |
9.96 (post-tax nominal vanilla) |
11.38% (nominal vanilla) |
9.50% (nominal) |
Debt
risk premium |
3.85% |
3.93% |
4.69% |
3.64% |
Revenue
requirement |
$372.1m (nominal) |
$345m (nominal) |
$348m (nominal) |
$361m (nominal) |
This concludes Pipes & Wires coverage of APT Allgas for the
next few years.
Ireland – the transmission grid asset owner price controls
Introduction
Back in November 2010 the Commission for Energy Regulation (CER) issued its final decision on the revenue that ESB Networks would be able to recover via its Transmission Use of System
(TUoS) agreements over the 3rd control period (PR3) from 1st
January 2011 to 31st December 2015. This article examines that final
decision, but more from an issues perspective rather than tabulating the € like
what we’ve done for the Australian decisions.
The wider context for PR3
The wider context for PR3 includes....
·
An increase in extension CapEx to
connect new renewable generation.
·
An increase in renewal CapEx as an
increasing volume of assets reach the end of their useful lives.
·
An expectation that further operational
efficiencies will be achieved.
So far
there wouldn’t appear to be anything unique to Ireland about these features.
The key components of PR3
Key components of PR3 include....
·
A requirement to make an efficiency
gain of €16.2m over 5 years embedded within the total allowable revenue of
€921m. The CER has not specified how these efficiencies are to be achieved.
·
Inclusion of an annual CapEx monitoring
program and a cost-benefit template for all CapEx projects over a yet-to-be-defined
figure to ensure efficient delivery.
·
A recognition that the determined WACC
must allow ESB Networks to competitively access the global capital markets to
fund its CapEx program.
·
Consideration of a move away from the
classical deterministic planning approach of (n-1) security to securing demand
with local generation.
·
Consideration of using surplus network
capacity to transmit injected wind power.
PR3 embodies a couple of features that
are not obvious in other transmission decisions, in particular the “unspecified
efficiency gains” and the move away from securing demand with grid capacity.
The CER will be undertaking a mid-term review of PR3, so that’s probably a good
time to see how things are starting to work out.
Aus – the Queensland electricity grid regulatory proposal
Introduction
Transmission grid owner Powerlink recently submitted its Regulatory Proposal to the Australian Energy Regulator (AER) for the 5 year control period beginning on 1st
July 2012. This article summarises the key features of that Proposal to set
some context for future analysis of the draft and final decisions.
Legal framework
The primary legal framework is the National Electricity Law (NEL) which is given legal effect in each jurisdiction of
the NEM by individual state laws. The NEL provides for the National Electricity Rules (NER) to be promulgated, with Chapter 6A applying
specifically to the economic regulation of transmission services.
Key features of Proposal
Key features of Powerlink’s proposal
include...
Parameter |
Proposal |
Draft decision |
Revised Proposal |
Final decision |
Total OpEx |
$1,002m |
|
|
|
Total CapEx |
$3,484m |
|
|
|
Opening capital base |
$6,579m |
|
|
|
Rate of return |
10.3% |
|
|
|
Revenue requirement |
$5,954m |
|
|
|
Pipes & Wires will revisit this
when the AER releases its draft decision.
Aus – South Australian gas distribution
final decision
Introduction
Previous
issues of Pipes & Wires (#96,
#99
and #100)
have examined Envestra’s proposed
Access Arrangement for its’ South Australian gas distribution networks for the
period 1st July 2011 to 30th June 2016. This article
concludes that examination with a summary of the Australian Energy Regulator’s (AER) Final
Decision.
Key aspects of the revised Access
Arrangement
Key
aspects of the process are set out in the following table...
Parameter |
Proposed AA |
Draft decision |
Revised AA |
Final decision |
Total
OpEx |
$335.69m (real 08/09) $344.1m (real 10/11) |
$260m (real 10/11) |
$336m (real 09/10) |
$305m (real 10/11) |
Total
CapEx |
$506.9m (real 08/09) $520m (real 10/11) |
$415m (real 10/11) |
$507m (real 08/09) |
$494m (real 10/11) |
Opening
capital base |
$1,030m (nominal) |
$1,018m (nominal) |
$1,030m (nominal) |
$1,024m (nominal) |
Closing
capital base |
$1,595.4m (nominal) |
$1,420m (nominal) |
$1,595.4m (nominal) |
$1,514m (nominal) |
Rate
of return |
10.64% (nominal post-tax) |
9.96% (nominal post-tax) |
10.98 (nominal) |
9.77% (nominal) |
Debt
risk premium |
3.39% |
3.93% |
4.67% |
3.81% |
Revenue
requirement |
$1,165m |
$985m |
$1,165m (nominal) |
$1,049m (nominal) |
This
concludes Pipes & Wires coverage of Envestra’s distribution business for
the next few years.
Mergers
& acquisitions
US
– follow up on AES’s acquisition bid for DPL
Introduction
Pipes
& Wires #101 introduced AES’ recent $4.7b acquisition bid for Dayton
Power & Light (DPL). This article examines a couple of recent issues that
have emerged.
Background
to the deal
This
deal is fairly simple ... AES
will pay $30 cash for each share of DPL’s
common stock (which represents about an 8.7% premium to DPL’s closing price on
the day of announcement) and assume $1.2b debt. Key drivers of the deal
include:
·
The need for AES to reduce its high
exposure to declining wholesale electricity prices by forward integrating into
a retail customer base. However this may only buy about 18 months of high
prices as DPL’s current regulated retail price (which is about 25% higher than
market prices) expires in late 2012.
·
The need for AES to improve the returns
on its cash reserves.
·
DPL’s strength of future earnings due
to pre-existing emission controls on its coal-fired plants.
·
Possible synergies between DPL and AES
subsidiary Indianapolis
Power & Light.
Recent
issues
Recent issues to emerge include:
·
Likely
credit downgrades for both the parent DPL and the subsidiary Dayton Power &
Light as both Moody’s and Fitch’s anticipate AES raising about $1.25b debt to
fund the share purchase, and then allocating that debt to DPL thereby
increasing its debt load to about $2.45b.
·
The
DoJ and the Federal
Trade Commission (FTC) granted an early termination of the waiting period required
under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976.
The approval of inter alia the FERC, the Public Utility Commission of Ohio and
DPL shareholders is still required so Pipes & Wires will make further
comment as those approvals emerge.
US
– regulatory hurdles for the NU – NStar deal
Introduction
Late in 2010 Northeast Utilities launched a
$4.17b bid for NStar, whilst
earlier this year the deal encountered 2 unexpected regulatory hurdles. This
article examines those hurdles, checks out the latest thinking on those hurdles
and then discusses what that might mean for future deals.
Hurdle
#1 – the Connecticut DPUC’s jurisdiction
The Connecticut Department of Public
Utility Control had originally concluded that under state law the DPUC’s
approval was only required when a new holding company would gain control over a
state utility, and that in this case there was no new holding company (NU was
not changing, simply acquiring another company). However the Attorney General,
the Senate President and the Office of Consumer
Counsel (OCC) argued that NStar would exert significant control over the
enlarged NU so although there was technically no new holding company, it could
be argued that NU was kind of a new company (and therefore subject to
approval).
In
early June 2011 the DPUC concluded that state law does not allow it to
intervene in the deal because inter alia
the 2 NU subsidiaries in Connecticut (Connecticut
Light & Power and Yankee
Gas) would still be subject to its jurisdiction. The OCC expressed its
disappointment with that conclusion, and in early July went to court to appeal
the DPUC’s decision. However the arguments proposed by the OCC as to why the
DPUC should intervene in the deal would appear to be already well covered by
the DPUC’s on-going powers to regulate those utilities.
Hurdle
#2 – the Massachusetts DPU’s increased burden of proof
The Massachusetts
Department of Public Utilities sought to impose a “demonstrate net benefits
to customers” burden of proof rather than the “no net harm to consumers”
criteria that has been used previously. Prima facie, NU and NStar have
publically quantified the merger benefits as well as confirming that grid
investment and clean energy initiatives will proceed, so this issue would
appear to hinge not so much on the creation of benefits, but rather the sharing
of those benefits with customers. However some concerns have been raised that
the merger could reduce electricity purchasing competition.
As of mid-July, the MDPU has commenced a
series of hearings around the burden of proof (and it appears that many more
issues will become entwined in the hearings). Pipes & Wires will comment
further as the hearings conclude.
US
– Gaz Metro beats Fortis to Central Vermont
Introduction
Pipes
& Wires #102 examined Canadian utility Fortis’ bid for the Central Vermont Public Service Corp (CVPSC).
This article briefly examines a competing bid from Gaz Metro Limited
Partnership, and notes that CVPSC accepted the Gaz Metro bid and terminated
the Fortis bid.
Recapping
Fortis bid
The key features of Fortis’ bid are....
·
A
cash offer of $35.10 for each CVPSC share, valuing CVPSC’s equity at $470m.
·
Assumption
of $230m of debt.
·
A
premium of 44% over CVPSC’s closing price on the NYSE.
Examining
Gaz Metro’s bid
Montreal-based Gaz Metro’s bid had the
following key features...
·
A
cash offer of $35.25 for each CVPSC share, valuing CVPSC’s equity at $472.4m.
·
A
premium of 45% over CVPSC’s closing price on the NYSE.
The
wider picture of Gaz Metro’s bid
Gaz Metro began in the 1890’s as the
Natural Gas Corporation of Quebec by lighting the streets of Montreal. Since
then it has grown to encompass the whole gas value chain, and has also acquired
Vermont Gas Systems in 1996 and Green Mountain Power
(GMP) in 2007 (both in the US state of Vermont).
That ownership of GMP would appear critical
to this deal, as GMP neighbors CVPSC. Hence Gaz Metro will be able to extract
merger synergies that (presumably) Fortis’ would not have been able to, and
therefore justifies Gaz Metro paying a slightly higher price. The merged entity
will have about 256,000 electric customers across Vermont, and will provide
opportunities for about $144m of cost savings over 10 years as well as investment
in renewables.
As previously noted, the deal will be
subject to regulatory approval.
Regulatory
policy
UK
– setting the framework for the next rail price reset
Introduction
It’s been a while since Pipes & Wires
examined the regulated rail sector, so a recent consultation paper from the Office Of Rail Regulation (ORR) in the
UK sparked my interest. This article examines the Periodic Review
2013 (PR13) paper that will shape the outcomes and access charges Network
Rail will be expected to deliver during the 5th Control Period (CP5)
starting on 1st April 2014 (with a yet-to-be-determined end date).
Wider
priorities feeding into PR13
Some of the wider priorities that will feed
into PR13 include....
·
An
expectation that the industry will improve its efficiency by about 30% by
2018/19 (compared to the 2008/09 baseline).
·
The
devolution of rail maintenance and repair from Network Rail to train operators.
·
Letting
rail asset management concessions to 3rd parties to encourage
efficiencies and provide comparative performance data.
·
A
disaggregation of management activity to a route level, enabling more
transparency and better comparison of costs.
·
A
migration toward longer franchises and more flexible specifications to ensure
that Network Rail and the train operator’s incentives are better aligned.
·
The
expectations of the governments of both England & Wales, and of Scotland
(these will be fed into PR13 as the High Level Output Statements (HLOS’s) in
July 2012), and the level of funding they will provide.
What
will CP5 look like ?
The key elements of CP5 will include....
·
The
use of a building block model, similar to most other regulated infrastructure.
·
Operational
(but not corporate) separation of Scotland from England & Wales.
·
Determination
of efficient expenditure at a route level (rather than at a business-wide
level).
·
Possible
ring-fencing of individual routes on a profit & loss basis.
·
A
possible move from narrowly defined outputs (eg. percent of trains on time) to
more widely defined outcomes (eg. percent of customers satisfied).
·
A
possible move from outcomes based solely on Network Rail’s performance to
outcomes based on the wider industry, to encourage alignment between Network
Rail and the train operators.
Next
steps
There is obviously a lot of work to be done
between now and early 2014, including work following on from the HLOS’s. Pipes
& Wires will check back on this issue as ORR publishes various papers.
Aus
& NZ – prescribing distribution charges
Introduction
Most of us accept that some restraint of
overall distribution revenue (revenue cap) or the charges to individual classes
of customers (weighted average price cap) is required. This article examines
moves on both sides of the Tasman Sea to increasingly prescribe how different
classes of distribution charges can be compiled.
Prescribing
the charges
The mechanisms used to increasingly
prescribe distribution charges are....
·
NZ
- the proposed introduction of a new Part 12a to the Electricity
Industry Participation Code (2010) to increasingly standardise distribution
tariff structures that will inter alia
reduce retailer re-pricing risk, prohibit distributors making retailers liable
for customer insolvency, introducing a more prescriptive approach to
negotiating Use of System Agreements (UoSA), and standardising prudential
arrangements.
·
Aus
- the proposed introduction of a new Chapter 5a to the National
Electricity Rules to inter alia
set out some guidelines for various classes of distribution charges (including
cost-reflective costs for new connections, and spreading the cost of capacity
upgrades).
The
subtle differences
On the face of it, it would seem that both
the Electricity Authority in NZ and the Australian Energy Regulator are tackling
similar issues. However there are definitely some subtle differences between
the 2 approaches, with the NZ approach shifting the balance of power more
towards electricity retailers and the Australian approach really only
emphasising what should be just good customer connection practice anyway.
Consulting
on the proposed changes
Consultation in NZ closed on 21st
June 2011, whilst consultation in Australia closes on 5th August
2011.
A bit of light reading…
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…
·
White Diamonds North.
·
Northwards March The Pylons.
·
Two Per Mile.
·
Live Lines (the old ESAA journal)
Conferences & training courses
The following
conferences and training courses are planned...
·
Infrastructure:
Investment & Regulation – Sydney, 21st October, 2011.
·
Fundamentals
of the NZ electricity industry – Auckland, 26th – 27th
October, 2011.
·
Fundamentals
of the NZ electricity industry – Wellington, 9th – 10th
November, 2011.
·
Fundamentals
of the NZ electricity industry – Wellington, 8th – 9th
May, 2012.
·
Fundamentals
of the NZ electricity industry – Auckland, 22nd – 23rd
May, 2012
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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.
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