From the
editor’s desk…
Welcome
to Pipes & Wires #151. This month starts with the completion of a major
merger in the US, and then looks at some gas regulatory decisions in the UK and
NZ. We then look at some renewable energy issues in the US and conclude by
examining 3 nuclear issues in South Africa, the UK and France. So … until next
month, happy reading…
Mergers & acquisitions
US – the Exelon – Pepco merger gets final approval
Headline
The Exelon – Pepco merger received its final regulatory approval in March 2016. The Washington DC
Public Service Commission (PSC) voted 2 – 1 to allow the merger to proceed, creating the largest
electric company in the US.
The PSC approval
Readers will have
noted from previous issues of Pipes & Wires that getting the Washington DC
PSC’s approval was a drawn out process with various lobby groups, customer
advocates and government agencies objecting to the merger. This resulted in a
revised merger proposal being submitted to the PSC which received their
approval.
The merged company
Exelon
is among the largest of America’s electric companies, with about 35,000 MW of
generation supplying about 7,800,000 customers through its subsidiaries Baltimore
Gas & Electric, Commonwealth
Edison and the Philadelphia Electric Company (PECO). Annual revenues are about $25b.
Pepco
Holdings supplies about 2,000,000 electric and gas customers in the Delaware,
Washington DC, Maryland and New Jersey areas through its regulated subsidiaries
Pepco, Delmarva Power and Atlantic
City Electric.
The
merged company will supply about 9,800,000 customers and have annual revenues
of about $29b.
More information on the merger
Check
the following references for more information on the merger…
· Pipes & Wires #134, #136, #140, #141, #142, #144, #145, #146, #147 and #150.
Closing comments
Phew …
this has been a long one, especially obtaining final approval in Washington DC.
Pipes & Wires will comment further as Exelon and Pepco integrate their
activities.
Regulatory decisions
UK – measuring the regulatory performance of gas businesses
Introduction
This
article looks at Ofgem’s recent performance assessments for the UK’s gas
transmission and distribution businesses for the year ending 31st March
2015.
The RIIO regulatory framework
A few
years ago the UK gas & electricity regulatory Ofgem introduced the RIIO regulatory model on 1st
April 2013 following the decision that the former RPI-X model had worked well
enough but that a better model was needed for the future (refer to Pipes & Wires #69, #94 and #101). This model is based on business outcomes of safety,
reliability and customer satisfaction rather than focusing on inputs such as
capital and operating costs.
The UK’s gas networks
The
UK’s gas is supplied by the following networks…
· The gas transmission pipelines are owned by National Grid Gas Transmission.
· The gas distribution networks are owned by 4 companies …
National Grid Gas, Northern Gas
Networks, Wales & West
Utilities, and Scotia Gas Networks.
Ofgem’s report on gas transmission
Key
features of the gas transmission networks report include…
· The required customer satisfaction, connections and
environmental performance has been met.
· The review of a serious incident is awaited before NGGT’s
safety performance can be determined.
· Ofgem is of the view that NGGT’s final under-spend for the 8
year regulatory period should be greater than what NGGT has forecast due to the
amendment and deferral of several major capital projects.
Ofgem’s report on gas distribution
Key
features of the gas distribution networks report include…
· A forecast out-performing of the cost allowance by Ł2.1b
over the 8 year regulatory control period, of which the gas companies will get
to retain 64% with the other 36% being returned to customers through lower
prices.
· All safety outputs are being achieved except for National
Grid Gas Distribution’s management of repair risk.
· Although network availability was 99.997%, Ofgem has some
concerns that some aspects of the reliability targets may be unachievable
whilst other aspects may encourage undesirable behavior (eg. scheduling repair
work to suit the gas company rather than the customer).
· In regard to customer satisfaction there was a mix of
over-performance for emergency response and repairs, but an under-performance
for planned interruptions.
Some comments about RIIO
Two
features of RIIO standout…
· Most obviously, an emphasis on high-level outputs whilst
letting the gas companies manage the internal tradeoffs between cost, work
programs and performance themselves.
· Less obviously, an 8 year regulatory period that provides
gas companies with greater flexibility to re-shuffle work programs and engage
contractors.
So the
big question is … is RIIO working, or perhaps more specifically is RIIO working
better than RPI-X ??
It’s obviously early days (only 2 years into the first 8 year period)
but it appears that a focus on outcomes that really matter to customers and
their communities seems to be working.
NZ – gas under pressure
Introduction
The Commerce
Commission recently released its cost of capital decision for any customised price-path (CPP) proposal made by Powerco for its
gas distribution business prior to the next CPP WACC Determination in March
2017. This article examines the key features of that determination.
Regulatory frameworks
The regulatory
framework is set out in clauses 5.3.22 to 5.3.29 of the Gas Distribution Services Input Methodologies Determination 2012.
Key features of the gas distribution WACC’s
Key features of
the gas distribution WACC’s include…
|
|
3 year |
4 year |
5 year |
|
Mid-point Vanilla WACC |
6.00% |
6.06% |
6.16% |
|
67th percentile Vanilla WACC |
6.53% |
6.59% |
6.68% |
NZ – decision not to inquire into gas metering services
Introduction
One of
the key functions of any economic regulator is to ensure that markets don’t
become dominated by a small number of suppliers, who might then increase prices
or reduce service levels. This article examines the Commerce Commission’s recent decision not to inquire into whether gas metering services should be
regulated.
Background
In
October 2012 Vector sought the Commission’s approval to acquire Contact
Energy’s gas metering business. The Commission approved Vector’s application in
April 2013 (Pipes & Wires # 122), and noted the following issues…
· It appeared that there was already limited competition
between Vector, Contact Energy and the other suppliers of gas metering
services.
· A comparison of the market both with and without the
acquisition suggested there would be no significant difference in the levels of
competition.
The
Commission has, however, remained concerned about the level of competition
having previously noted that Vector and Powerco control about 96% of the market
for gas metering services.
The Commission’s decision
In
April 2016 the Commission decided it would not inquire into gas metering
services pursuant to Subpart 2 of Part 4 of the Commerce Act 1986, but would continue to monitor the price of such services
in the future. The reasons for the Commission’s decision was that the benefits
of regulation would be unlikely to out-weight the costs of an inquiry and any
possible subsequent regulation … analysis suggested that the saving might be
between $0.63 and $1.03 per month for an average consumer.
Renewables
US – Nevada PUC faces law suit over solar decision
Introduction
The Alliance for
Solar Choice (TASC) recently filed a law suit against the Nevada Public Utilities
Commission (PUC) in regard to the PUC’s recent approval of Nevada
Power’s tariff realignments.
Background
Pipes & Wires #149 examined the big hit that rooftop solar took in the US
state of Nevada as the PUC approved Nevada Power’s plans to increase its monthly connection tariff whilst also
significantly reducing its feed-in tariff. This tariff re-alignment included
the added dimension of applying to existing rooftop solar customers ie. no grandfathering.
The sequence of events to date
The sequence
of events includes…
· Nevada Power sought the PUC’s approval to increase its
monthly fixed connection charge from $12.75 to $17.90 on 1st January
2016 and then to $38.51 on 1st January 2020, and to also reduce its
feed-in tariff from 11c per kWh to 9c per kWh on 1st January 2016
and then to 2.6c per kWh on 1st January 2020.
· The Alliance for Solar Choice (TASC) requested the Nevada
Public Utilities Commission to delay the new tariffs that were scheduled for 1st
January 2016.
· The staff of the PUC recommended that the request to delay
be denied ie. Nevada Power will be allowed to proceed with the tariff
increases.
· Solar advocates claim that the PUC’s decision will mean the
end of the solar industry in Nevada, and indeed one supplier (Solar City) has
announced it will no longer supply or install solar in Nevada.
· After extensive outcry from the solar industry, the PUC
revised its decision with a view to requiring grandfathering of existing solar
tariffs, meaning that the proposed ramping up of the monthly tariff to $38.51 would
occur by 2028 instead of 2020.
TASC’s law suit
Information
on the precise basis for TASC’s law suit seems hard to find. There are a couple
of readily observable facts such as the PUC decision being a “big win for the
utility at the expense of solar users”, and “unless relief is granted by the
court, rooftop solar power generation may well cease to exist in Nevada”, but
there don’t seem to be any obvious points of law. Some might even say it sounds
like a “sob … sob … we didn’t get our way” sort of thing.
Why is this law suit so significant ??
Electric
companies are at a crossroads in regard to a raft of issues around rooftop
solar and who pays how much to connect and inject. Nevada had apparently
reached a position where customers with rooftop solar would pay monthly
connection charges and be paid feed-in tariffs that (i) reflect the electric
company’s costs, and (ii) don’t extract a subsidy from non-solar customers. This
law suit seeks to over-turn what appears to be an analytically sound decision
on the basis of “it’s not fair”.
US – going for 100% renewables in Hawaii
Introduction
The
Governor of the US state of Hawaii recently signed House Bill 623 into law mandating 100% renewable energy by 2045. This
article unpacks exactly what HB623 will require, how the energy industry might
achieve it, and what the price and reliability trade-offs are likely to be.
What exactly does HB623 require ??
Essentially
HB623 requires a ramping up of the percentage of renewable electricity sold by
each electric company as follows…
|
Date |
Percentage
to be renewable |
|
31st December 2020 |
30% |
|
31st December 2030 |
40% |
|
31st December 2040 |
70% |
|
31st December 2045 |
100% |
The
remarks preceding the above table in HB623’s text note that the goal of
extending the renewable portfolio goals beyond 2030 should be subject to the
following considerations…
· It must benefit the Hawaiian economy.
· It must benefit all electric customers.
· It must maintain customer affordability.
· It does not induce renewable energy developers to
artificially increase the price of renewable energy in Hawaii.
These
remarks suggest that the Hawaiian government has recognised the affordability
issues that have arisen in other jurisdictions, and is providing for a useful
“pause and consider” at around 40% renewables penetration.
Where is Hawaii at with renewable penetration
??
Historically
about 75% of Hawaii’s electricity has been generated by oil-fired plant, with a
further 15% generated by coal-fired plant and the remaining 10% from
renewables. Those oil and coal imports have understandably resulted in high
electricity prices, in fact the highest in the United States being some 20%
higher than the next most expensive.
During
the 2014 year, grid–scale renewable generation climbed to 13% (including
bio-mass and geothermal), with a further 8% from small-scale renewables. So in
broad terms Hawaii is at about 20% renewables.
What specific initiatives will be required to achieve 100% renewables ??
Well
obviously there is going to have to be a significant migration from oil-fired
and coal-fired generation to renewables. A little research reveals the
following…
· About 50% of Hawaii’s generation capacity (MW) is
intermittent … about 1,465MW of the total 2,785MW.
· There is about 145MW of potential hydro sites. The fact that
many of these sites were identified up to 40 years ago suggests they are
unviable viz-a-viz historical and current prices.
· There appears to be very limited potential for further
geothermal development over and above the 60MW of existing and planned
capacity.
This
would suggest that future renewable investment will need to be mainly wind and
solar, which is of course intermittent. This will be compounded by a lack of
quick-start generation to buffer those renewables, and then possibly further
compounded by the rapid life consumption of the oil and coal-fired steam
turbines if they are used to follow load profiles.
What reliability and price trade-offs are likely to result ??
The
above analysis suggests that achieving the required renewables penetration will
require significant amounts of intermittent generation. This requires the state
of Hawaii to make some strategic choices along the following lines…
· Build sufficient “installed capacity” to meet “maximum
demand”. This choice embodies an acceptance that the lights will go out when
the wind stops blowing or clouds cover the sun.
· Build extra capacity based on the likely availability of
wind and solar plant. This choice embodies a much higher cost which will need
to be recovered from customers.
Either
choice will almost certainly result in a significant shift from the existing
reliability-price trade-off (as any movement on the energy trilemma does). As
noted above, the legislation includes what appears to be a “pause &
consider” at about 40% renewable penetration but it is not clear that there is
a full awareness of exactly how tough that choice might be.
Nuclear energy
South Africa – progress on the nuclear station
Introduction
South
Africa’s National Nuclear Regulator recently received 2 site license applications from Eskom ahead of the government’s expected RFP for new nuclear
generation. This article looks back over South Africa’s recent moves toward
additional nuclear capacity and examines Eskom’s applications.
Recent moves toward additional nuclear capacity
After
operating the Koeburg nuclear station since 1984, the South
African Energy Minister Dipuo
Peters signed off a
proposal for 9,600MW of nuclear capacity that would see commissioning by about
2024 or 2025. The likely cost is estimated to be between R400b and R1,000b.
Eskom’s proposed sites
Eskom’s
proposed sites are…
· Thyspunt, in the Eastern Cape.
· Duynefontein, in the Western Cape just north of Koeburg.
The various responses
Not
surprisingly, there have been a wide range of responses…
· Eskom is confident that it can fund, build and operate new nuclear stations.
· New Nuclear Watch
Europe expressed confidence in the safety of nuclear, and noted
the comparability of total life-cycle costs with coal-fired stations.
· NERSA has not done any modelling of the impact on tariffs,
indicating that it would take up to 15 years to get the first unit operational.
· Rating agency Moody’s seem nervous about how the cost of
building 2 nuclear stations will impact on Eskom’s credit worthiness.
· The latest World Nuclear Industry status report paints a less than optimistic picture of declining nuclear
operation and government hesitancy over new nuclear generation.
Next steps
As noted
above, the next step is the release of the RFP. A key issue will be the
electricity sector’s interest in that RFP … Pipes & wires will comment as
that interest becomes apparent.
England – progress on Hinkley Point C
Introduction
EDF
Energy’s proposed Hinkley Point C nuclear station has featured in the news
recently, so Pipes & Wires thought it was time to have another look at this
and try to scratch through some of the media hype and get to the real issues.
The major issues to date
A
couple of the major issues to date include…
· The escalating cost. The publically stated costs have
increased from an initial Ł10b through a series of significant increases to
Ł24.5b, although recent media reports are saying about Ł18b.
· Technical difficulties arising during the construction of
the Flamanville #3 reactor in France which is using the same 1,600MW European Pressurised Reactors (EPR) proposed for Hinkley Point C. It has been suggested
that any decision on Hinkley Point C should be deferred until at least 2019
when the realities of Flamanville will be clearer.
· The drawn out process of obtaining a 35 year Contract For
Differences funding model that will provide certainty of investment (funny … if
it was a solar panel there would’ve been no trouble getting that certainty of
investment).
· An investigation by the EU to determine whether the CFD
funding model breached the EU prohibition on state aid. An amended model was
finally approved by the EU.
· A challenge to that decision by Austria and Luxembourg
claiming that any state aid must be targeted towards renewable energy.
· On-going criticism that the finally agreed price of Ł92.50
per MWh guaranteed for 35 years with inflation adjustments (3x the current
price) is just plain crazy.
· An internal report to the EDF Energy board warning that it
would technically impossible to complete the 2 reactors by the proposed 2025
completion date.
· A board level suggestion that the whole Hinkley Point C
project will be financially ruinous for EDF Energy’s parent company EDF. This
resulted in the resignation of EDF’s finance director who was a firm critic of
the project.
· Moody’s noted that EDF’s declining operating cashflow
resulting from softer electricity prices and existing debt obligations may
further exacerbate the risks associated with Hinkley Point C.
Current status of the decision
So …
where does that leave it ?? Amongst a quagmire of
engineering, financial and political difficulties EDF officials and ministers
of the French government have given strong assurances to the UK government that
Hinkley Point C will “definitely proceed” even if the French government has to
recapitalize EDF. A further announcement is expected in a few months….
France – what exactly is happening at Flamanville
?
Introduction
Most
recent discussions about new nuclear generation seem to stumble across
Flamanville with vague utterances about “engineering difficulties”, “delays”
and “cost increases”. This short article takes a look at the Flamanville #3
reactor and tries to uncover exactly what the issues are.
The existing Flamanville power station
The
existing Flamanville station has two 1,300 MW Pressurised Water Reactors (PWR’s) that were placed into commercial operation in 1986
and 1987 respectively. The station is located near the village of Flamanville
in the Manche area of north-western France.
The reactor type being installed
The
third reactor being installed at Flamanville is a 1,600 MW European Pressurised Reactor (EPR) designed by Areva. Construction began in December
2007 with an expected completion of about April 2012. Then came a series of
cost escalations and completion delays, with the estimated start date now being
late 2018.
The specific problems
Pipes
& Wires #145 noted the following 2 technical problems…
· Reduced mechanical strength of the pressure vessel head due
to high carbon concentrations.
· Discovery of multiple malfunctioning relief valves on the
reactor vessel.
Expanding
on the first point, tests performed in 2014 revealed that some zones of the reactor vessel and cover
included significant concentrations of carbon. Those concentrations of carbon
reduce the resilience of the steel and reduce its ability to resist crack
propagation.
The regulator’s decisions
Areva
informed the French Nuclear Regulator (ASN) which said that it would consider Areva’s proposed
remedial actions and issue a decision, which is now not expected until the end
of 2016. That decision is expected to delay commercial operation until late
2018, with the possibility that a worst-case decision by the ASN requiring
replacement of the vessel could add further delays and costs.
The costs and delays
The
cost and expected completion dates are approximately as follows…
|
Date
of announcement |
Expect
cost |
Expected
completion date |
|
December
2007 (original announcement) |
€3.3b |
April 2012 |
|
December
2012 |
€8.5b |
2016 |
|
September
2015 |
€10.5b |
Late 2018 |
So the
latest estimates are 6˝ years of delays and €7.2b of cost over-runs.
Recent client projects
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 from Utility
Consultants....
· Advising a major equipment supplier on battery and solar
trends.
· Leading an energy trust workshop on future trends for the
distribution industry.
· Facilitating an executive workshop on the future trends and
issues for the distribution industry.
· Advising a major global investment bank on the revenue and
capital cost characteristics of the New Zealand generation industry.
· Assessing the investment characteristics of proposed CapEx
increases to an investor-owned electric network.
· Assessing three EDB’s asset management practices against ISO
55000:2014.
· Assessing an EDB’s compliance with the lines – generation
separation requirements of the Electricity Industry Act 2010.
· Assessing an EDB’s compliance with the Electricity Industry
Participation Code.
· Compiling safe operating procedures for a wide range of
distribution switches.
· Advising an investor on the investment characteristics and
regulatory constraints of small hydro development and grid connection.
· Reviewing the engineering aspects of an EDB’s lines pricing
methodology.
· Advising a major global consultancy on specific features of
emerging electricity transmission and distribution regulatory regimes, including
period length, potential for re-opening determinations, caps & collars,
total expenditure levels and incentive mechanisms.
· Examining the economic efficiencies of an EDB’s pricing
methodologies.
· Advised on the wider philosophical and potential tax issues
of the way consumer discounts are paid by EDB’s.
· Prepared an independent engineer’s report to justify
proposed alternative asset lives.
· 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.
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 photo’s with humorous captions looks at some of the salient
features of price control. Pick here to download.
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…
· Economic Operation Of Power Systems
(Kirchmayer).
· Distribution Of Electricity (WT Henley, the cable
manufacturer)
· Northwards March The
Pylons.
· Two Per Mile.
· Live Lines (the old ESAA journal).
· The Engineering History Of Electric
Supply In New Zealand.
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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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