From the editor’s
desk…
Welcome
to Pipes & Wires #101. This month continue the recent theme of mergers in
the US electric industry, and then also look at 2 topical security of supply
issues in the US.
We
also examine a wide range of energy and regulatory policy decisions from around
the world, and conclude with a look at a gas transmission regulatory decision
in Australia.
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Mergers & acquisitions
US – AES makes a bid for Dayton Power
& Light
Introduction
The
US electric power industry has seen a flurry of recent mergers, and indeed Pipes
& Wires #100 indicated that it would be surprising if further mergers
didn’t emerge in the near future. This article examines AES Corporation’s recent cash bid for
DPL Inc.
A bit about the key players
The
key players of this deal are:
·
AES Corporation is a multi-national
utility, with 132 generation plants in 28 countries, and US$17b in annual
revenues.
·
DPL supplies 500,000 electric customers
in western and central Ohio, and has annual revenues of US$1.9b.
The proposed deal and its’ drivers
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. 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.
So it would appear that the drivers for
this deal are somewhat different from other recent deals which have been driven
by the need to increase scale to better fund emission controls and new
transmission investment. It is also likely that a much narrower array of
regulatory approvals will be required as DPL only operates within 1 state.
US
– Exelon makes a bid for Constellation
Introduction
Following
on from the comments in the previous article that it would be surprising if
further mergers didn’t emerge in the near future, this article examines Exelon Corp’s recent bid for Constellation Energy Group.
The
key players
The key players in this deal are:
·
Exelon
owns 32,000MW of generation and supplies 5,400,000 electric customers in
northern Illinois and southern Pennsylvania. Annual revenue is about $19b.
·
Constellation
owns 12,000MW of generation and supplies 1,200,000 electric and 630,000 gas
customers in Maryland (through its subsidiary Baltimore Gas & Electric).
Annual revenue is about $14b.
Some
details of the bid
Exelon is offering 0.93 of its shares for
each Constellation share, valuing the deal at about $7.7b and representing a
premium of about 12.5% over Constellation’s closing price.
Key
drivers of the bid
Likely drivers of the deal include geographical
synergies between Exelon’s service territory in southern Pennsylvania and
Constellation’s BGE territory in Maryland, and possibly some forward
integration into BGE’s retail market to ease the effect of soft wholesale power
markets.
US - a running total of recent deals
Just
so we can keep track of it all, recent and present deals in the US include:
|
Deal |
Consideration |
Premium |
Dimensions of
merged entity |
|
PPL’s acquisition of LG&E and KU (from E.On US) |
$5.6b
cash and $800m debt |
|
20,000MW
of generation, 2,600,000 electric customers |
|
First Energy Corp
acquires Allegheny
Energy |
$4.4b
in stock and $3.8b debt |
10.8% |
23,700MW
of generation, 6,000,000 electric customers, annual revenue of $16b. |
|
Northeast Utilities acquisition of NStar |
$4.17b
in stock |
0% |
3,000,000
electric and 505,000 gas customers, annual revenue of $8.4b. |
|
Duke Energy’s acquisition
of Progress Energy |
$13.8b
in stock and $12.2b debt |
4% |
56,000MW
of generation, 7,100,000 electric customers. |
|
|
$3.5b
cash |
8.7% |
Annual
revenue of $19b, 970,000 electric customers. |
|
Exelon’s bid for Constellation |
$7.7b
in stock |
12.5% |
44,000MW
of generation, 6,600,000 electric customers, annual revenue of $33b. |
Asset strategy
US – using batteries to complement wind
Introduction
Most
of us are very aware of the limitations of wind. This article examines Duke Energy’s use of batteries at a
Texas wind farm to provide power when the wind stops blowing.
The specific technology
The Notrees wind farm will have 36MW of battery banks, provided by Xtreme Power of Austin, Texas. The specific technology is Xtreme’s
PowerCells which are essentially 12V, 1kWh
ultra-low impedance dry-cell batteries and a whole bunch of fancy electronics
(collectively called the Dynamic Power Resources).
What about the $$$
So
what’s it all costing ? The Notrees DPR
will cost $43m (which includes a Department of
Energy grant of $22m), so on the face of it that looks like about
$1,200/kW. A bit of rough (and indeed simplistic) analysis would suggest that
this is towards the low end of installed costs, and that batteries could well
be a good alternative to, say, gas turbines for complementing an existing wind
farm.
Industry reshuffling
Aus – reshuffling the Queensland
generators
Introduction
Breaking
up monolithic generators as part of the industry reform process is certainly
nothing new, however the relative competitiveness of the resulting generators
can often be a vexing issue. This article examines the recent restructuring of
generation businesses in the Australian state of Queensland.
The original breakup
The
original breakup of the former Queensland Electricity Commission (which
transitioned through Austa Electric) resulted in the following generation
companies:
·
CS Energy – Callide,
Swanbank, Mica Creek (not NEM connected) and Kogan Creek (constructed after break up).
·
Tarong Energy – Tarong, Wivenhoe and Tarong North (constructed after breakup).
·
Stanwell Corporation – Stanwell,
Mackay and several smaller hydro’s.
The Gladstone
power station asset (but not the power purchase agreement) was sold to Comalco in March 1994 prior to the reform process.
The current issue
Around
the time when the 3 competing generators were established, each Australian
state operated its own electricity market, and moreover most electricity was
sold on-market. Each of the 3 generators had a similar (or at least not wildly
dissimilar) cost advantage.
Pipes
& Wires #51 examined the sale of Energex and Ergon Energy’s retail businesses ahead of full retail contestability
(FRC). The resulting sales of Energex’
retail business to Origin Energy
and Ergon’s large customer retail business to Australian Gas Light (AGL) in 2007 and the
subsequent vertical integration has depressed wholesale prices. While this
might be good news for customers, it makes it difficult for legacy coal-fired
plant to compete.
The new structure
The
proposed restructuring will see a consolidation of the 3 existing generators
into 2 larger generators as follows:
·
CS Energy – Callide B, Callide C, Kogan Creek, Wivenhoe and
the Gladstone power purchase agreement
·
Stanwell Tarong – Stanwell, Tarong, Tarong North, the Collinsville power purchase agreement, Swanbank
E, Mica Creek (not NEM connected), the hydro’s, and the retirement of Swanbank
B.
The
new companies take effect from 1st July 2011, and it will be
interesting to see whether the reshuffling and consolidation has improved the
cost position.
Austria – unbundling gas transmission
Introduction
Unbundling
of lines and energy as part of the energy sector reform process is certainly
widely understood, even if still largely controversial. This article briefly
examines the proposed unbundling of Austria’s gas transmission system operators
(TSO’s) under laws pursuant to the EU’s Third Package.
The EU Third Package
The EU’s
Third Energy Package of September 2007 aimed to benefit all citizens by
providing greater choices and fairer prices. Highest amongst the EU’s proposed
approach was unbundling of lines and energy, with the consequent requirement
for all member countries to implement unbundling. The EU’s initial thoughts
proposed 2 options for unbundling, viz:
· Full ownership separation of lines (probably including
pipes) and energy.
· Retaining ownership but placing full operational and
investment control in the hands of an independent system operator (ISO).
Early
July 2008 saw the EU Parliament
reject forced unbundling of vertically integrated gas businesses, siding with
many member countries. That diluted draft law would require internal separation
… the much applauded “Third Way” … which represents a significant watering down
of the ISO option. In regard to electricity, however, it seemed the EU is
determined to have nothing less than full ownership unbundling. The Package was
finally passed into EU law in September 2009, with individual member countries
having 18 months to implement those reforms via their own legislation.
The utilities to be unbundled
The
TSO’s that will have to unbundle are:
·
OMV
Gas GmbH, which owns and operates 2,000km of transmission pipelines within
Austria and represents a major European hub.
·
TAG GmbH, which operates a 380km
gas transmission pipeline between Baumgarten and Arnoldstein.
·
BOG
GmbH, which holds the marketing rights for the 245km gas transmission
pipeline from Baumgarten to Oberkappel.
The proposed unbundling
It
appears that each of the TSO’s will have to choose between Ownership
Unbundling, ISO and the “Third Way” (management and investment being controlled
by a separate subsidiary). There are understandably a range of industry
reshuffling, market positioning and commercial issues around each option, so
this will be worth watching.
Energy policy
US – what future hath coal ?
Introduction
Pipes
& Wires #90 included an article with this somewhat witty heading, and
it seemed appropriate to recycle it for this article which examines Senate Bill 5769
in the US state of Washington which aims to close the almost 40 year old 1,460MW
Centralia coal-fired power station by 2025. To give it some perspective, Centralia
generates between 8% and 10% of Washington’s electricity.
A few details of Senate Bill 5769
Senate Bill 5769 recites at length the
state’s concern about the toxic residues of coal combustion, and how previous
commitments to reducing CO2 emissions require further action. In
particular, any electric generating station that emitted more than 1,000,000
tons of greenhouse gases in each of the calendar years 2005, 2006 and 2007 will
be subject to an emissions standard applicable from 31st December
2020. A “qualifying facility” may petition the Governor to defer the
applicability of the standard until 31st December 2025 at the
latest.
Around the time of writing this article,
the Senate had voted 33-14 to send the Bill to Governor Christine Gregoire, who then
signed the Bill into law.
What the stakeholders are saying
So what are all the stakeholders saying
? A search of the local news reveals an unsurprising diversity of opinions:
·
Centralia’s owners, TransAlta, seem broadly accepting of the Bill, presumably recognising that phasing out coal is the way of the world at the
moment. TransAlta does however note that the amendments don’t significantly
alter a previously reached joint agreement between TransAlta, the state government, organised labor and environmental groups (Editor’s note – it might be
questioned why any variation from a prior agreement occurred at all).
·
Environmental groups seem delighted,
with the closure not coming soon enough for some.
·
Centralia employees are unhappy that
job losses are almost certain to occur (and with no other coal-fired plants in
Washington, that would mean relocating inter-state for many).
·
Officials from the Centralia area are
unhappy that the plant closure would be another economic loss to the community
(about $26m in wage per year).
·
Consumer lobbyists are unhappy with the
likely price of replacement generation.
·
Representatives (judging by the
overwhelming 87 to 9 support for the Bill) seem happy with the Bill.
Has anyone considered security of supply ?
On the whole, it would appear not. It
is certainly not clear that the gas-fired combined cycle plant that TransAlta will be incentivised to
replace Centralia with will replace all 1,460MW. So the funny thing is that
Washington may end up importing coal-fired electricity from other states (which
it already does in the form of a coal-fired station in Montana owned by Puget
Sound Energy). Gee ... where have we come across that before ? Like ... uh ...
anti-nuclear Germany importing nuclear electricity from France and the Czech
Republic !!!
France – downward pressure on feed-in tariffs
Introduction
The area of feed-in tariffs has had a
rather rapid path to maturity, with several jurisdictions rapidly reducing the
tariff as it became apparent that many people’s motivation was simply financial
rather than environmental. This article examines the new regulatory framework
for photo-voltaic (PV) generators in France, and then examines some wider
general policy issues.
A bit of background to the French PV sector
Installed PV capacity has grown rapidly
in France, from 81MW at the end of 2008 to 1,025MW at the end of 2010, which is
pretty close to France’s target of 1,100MW by the end of 2012. Like several
jurisdictions, France curtailed the former feed-in tariffs to reduce
“inflation” in the PV sector, even going as far to use the phrase “excessive
returns”. This created a period of uncertainty until the recently announced
regulations commenced.
The French regulatory framework
Key elements of the French PV
regulatory framework include:
·
PV plants up to 100kW will be paid a
feed-in tariff that will initially be 20% lower than the tariffs that were in
force on 1st September 2010, and will be reviewed quarterly.
·
Larger plants will submit tenders
(presumably like the German and Californian “reverse auction” model).
·
The government expects future tariff
reviews to reflect an expected cost reduction of 10% per year.
·
A requirement to dismantle and recycle
PV plants at the end of their lives.
Media commentary suggests that the
French tariff reductions may well encourage similar reductions in Germany and
the Czech Republic.
Some wider issues on the whole renewables sector
Probably the most significant issue is
how this whole feed-in tariff thing has become such a double-edged sword to the
policy makers and regulators, so just a couple of observations to close this
article:
·
On one hand renewables (especially PV) are
the darling of many bureaucrats, but on the other hand the high uptake has
ostensibly been for the filthy lucre rather than to save the planet.
·
A whole industry has been built around
renewables and subsidies, and that industry (along with the Green parties) is
understandably upset that those subsidies (the feed-in tariffs) are being
reined in.
·
Those advocating subsidies for
renewables are finding themselves caught in the gulf between “the fossil fuel
industry got plenty of subsidies” on the one hand and on the other hand subsidies
being unacceptable in these apparently more enlightened times.
·
The true costs of the renewable
industry and the jobs it has created are becoming more visible (I read
somewhere a while back that each renewable energy job created in somewhere like
Spain or Portugal was costing 3x the average wage).
Regulatory policy
Belgium – protecting consumers from
price volatility
Introduction
One
of the key purposes of energy sector reforms is to firstly put downward
pressure on prices, and secondly to ensure that any resulting price reductions
are shared with customers. This article examines whether there might be a
disconnect in Belgium’s proposed legislation between wanting to pass on price
reductions to customers on the one hand, but protect customers from price
volatility on the other hand.
Background
The EU’s
Third Energy Package that was released in September 2007 set out several
ambitious goals for Europe’s energy sector that included options for unbundling
lines from energy, improving security of supply particularly during gas supply
interruptions, and improved customer rights. Earlier in 2011, the Commission
de Régulation de l'Électricité et du Gaz (CREG) published a
position paper on implementing the Third
Package that discussed
inter alia how customers might be
protected from price volatility.
Thinking about price volatility
Perhaps
a good starting point to examine this issue would be the strong coupling of
Belgium’s gas and electricity prices to the price of underlying gas imports
from Russia and the Middle East. Implicit in that underlying gas price will be
a level of volatility that is only likely to increase, so one way or another
the electric and gas utilities in Belgium will be exposed to price
volatilities.
Those
utilities could take (broadly) either of 2 approaches:
·
They could pass on that volatility (and
the associated volatility risk) to their customers, who would accept the price
swings.
·
They could absorb that volatility (and
risk) and expose their customers to more certain prices. In doing so, they
would need to charge a premium for accepting that risk.
It would appear, however, that the officials’
preference would be for the utilities to pass on the low prices whilst
absorbing high prices, a kind of customers having it both ways sort of approach.
So it will be interesting to see how the utilities respond to any final legal
requirements along those lines.
UK – setting the framework for RIIO-GD1
Introduction
The UK’s gas distribution companies are currently
subject to GDPCR
2007-13, which runs from 1st April 2007 until 31st
March 2013. As most of us will be aware, this GDPCR is based on the RPI-X
approach. This article examines OFGEM’s RIIO-GD1
which will reflect the new Revenue = Incentives + Innovations + Outputs
approach resulting from the recent RPI-X @ 20 review.
A quick recap of the RPI-X @ 20 review
Back in 2008, OFGEM announced that the RPI-X approach
would be substantially overhauled. A few
of the issues that need to be considered going forward include….
·
The formation of a new EU-wide
regulatory body.
·
The EU’s views on vertical integration
of the energy giants.
·
Climate change and renewable
obligations.
·
Increasing complexity of price
controls.
·
The end of “easy” OpEx efficiency
gains.
·
Concerns that the RPI regime is moving
toward a Rates-based regime.
·
Concerns that valuation and financial
parameters and principles may have become less valid over time.
·
The need to properly recognise
increased security requirements since 9/11 and 7/7.
In
late July 2010, OFGEM released a consultation
paper setting out its proposed adoption of the RIIO Model – “revenue set to
deliver strong incentives, innovation and outputs”. Some of the significant
headline features include...
·
An “outputs led” philosophy in which
the price control would focus on lines businesses delivering specified
outcomes.
·
Retention of ex-ante control which
would include a return on RAV.
·
A commitment to publishing the
principles for setting a WACC-based return, with subsequent cross-checking
against credit ratings.
OFGEM
was also of a mind to establish an 8 year control period with a mid-term
review, and also anticipated the EU’s “Third Package”
of energy reforms which any emerging regulatory framework must be consistent
with.
Key elements of RIIO-GD1
The key elements of RIIO-GD1
are broadly as follows:
· Increased flexibility to deliver
what customers want from a network (as distinct from delivering a
pre-determined set of price, capacity, security and reliability outcomes).
· Lengthening the price control
from 5 to 8 years to encourage a longer-term focus.
· Higher returns for delivering
high quality services at lower costs, with the incentive of avoiding more
intrusive price controls.
· Allowing new entrants to take
responsibility for large investment projects.
· Providing clear investment
signals to investors to ensure utilities remain financeable.
· An expectation that distribution
companies will engage more routinely and regularly with their customers to
better determine those customers’ preferences.
This all sounds very grand, and indeed those who have
examined the EU’s expectations of “Increased Choice – Lower Prices – Improved
Security” might notice some common themes. In particular it will be interesting
to see exactly how (and the priority that is given to) those investment signals
end up. Pipes & Wires will follow this one closely as news emerges.
Regulatory decisions
Aus
– the Amadeus Gas Pipeline draft decision
Introduction
Pipes & Wires has worked its way around
the access arrangement decisions for most of Australia’s gas transmission
pipelines. This article examines the Australian
Energy Regulator’s (AER) recent draft
decision to not accept NT Gas’ proposed access arrangement for the Amadeus Gas Pipeline (AGP)
for the period 1st July 2011 to 30th June 2016.
A
bit about the Amadeus Gas Pipeline
The AGP stretches 1,658km from Palm Valley
and Mereenie in central Australia to Darwin, and has a capacity of about 100TJ
per day. The sole connected user of the AGP is the Power & Water Corporation,
for the supply of its gas-fired generation.
The
legal framework
The AER’s powers and duties, including with
respect to regulating the AGP, are set out in the National
Gas Law (NGL) and the National
Gas Rules (NGR). The NGL requires the AER to perform its functions in a
manner likely to contribute to the National Gas Objective “to promote
investment in, and efficient operation of, natural gas services for the long
term interests of consumers of natural gas with respect to price, quality,
safety, reliability and security of supply of natural gas”.
The
draft decision
The following table compares the AER’s
draft decision with NT Gas’ proposed access arrangement (and will be completed
as the revised arrangement and final decision come to hand):
|
Component |
Proposed access arrangement |
Draft decision |
Revised access arrangement |
Final decision |
|
Total revenue requirement |
$169.8m |
$129.7m |
|
|
|
Reference tariff |
$0.7596/GJ/day |
$0.5778/GJ/day |
|
|
|
Nominal risk free
rate |
5.48% |
5.53% |
|
|
|
Inflation forecast |
2.50%/yr |
2.57%/yr |
|
|
|
Real risk free
rate |
2.66% |
2.89% |
|
|
|
Cost of debt |
10.94% |
9.32% |
|
|
|
Debt risk premium |
5.46% |
3.79% |
|
|
|
Cost of equity |
11.98% |
10.335% |
|
|
|
Equity beta |
1.00 |
0.80 |
|
|
|
Market risk
premium |
6.50% |
6.00% |
|
|
|
Gearing |
60% |
60% |
|
|
|
Nominal vanilla WACC |
11.36% |
9.72% |
|
|
|
Opening capital base |
$112.4m |
$97.0m |
|
|
|
CapEx |
$14.4m |
$13.9m |
|
|
|
OpEx |
$73.0m |
$58.6m |
|
|
The AER’s draft decision is to not accept
the proposed access arrangement, and to require NT Gas to make a number of
specific revisions. Pipes & Wires will make further comment as the revised
arrangement and the final decision emerge.
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.
·
Marlborough Will Shine Through.
·
Two Per Mile.
·
Live Lines (the old ESAA journal)
Conferences & training courses
The following
training courses will be run by Conferenz...
·
ENEX
– New Zealand’s Oil & Gas Event – New Plymouth, 9th – 10th
June, 2011.
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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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