From the
editor’s desk…
Welcome
to Pipes & Wires #136 … this month we start with 2 cost of capital
determinations in NZ before examining the emerging ISO 37120 standard and what
it might mean for electric companies. We then examine a regulatory decision and
2 mergers in the US, followed by a draft regulatory determination in the UK.
This issue concludes with an examination of solar tariffs in Australia and a discussion
of those tariffs need to reconcile with distribution pricing.
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 global investment bank
on the revenue and capital cost characteristics of the New Zealand generation
industry.
· Assessing the investment
characteristics of an investor-owned electric network.
· Assessing a large 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.
· 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.
Matters for attention in NZ
Readers’
attention is drawn to the following matters…
· Revised standard NZS7901:2014 for
Safety Management Systems.
· Likely increased obligations for worker
safety.
New Zealand
NZ – determining the WACC for electric,
gas and airports
Introduction
The
Commerce Commission has recently determined the cost of capital (Vanilla WACC) that will apply to the
following infrastructure businesses for the information disclosure year ending
on 30th June 2015...
· Transpower.
· Vector and GasNet’s gas pipeline businesses.
· Auckland and Christchurch
Airports’ specified airport services.
This
article examines the key features of that determination.
Legal frameworks
These
WACC’s have been compiled pursuant to…
· Clauses 2.4.1 to 2.4.7 of the Commerce Act (Transpower Input Methodologies) Determination 2012.
· Clauses 2.4.1 to 2.4.7 of the Commerce Act (Gas Distribution Services Input Methodologies) Determination
2012.
· Clauses 2.4.1 to 2.4.7 of the Commerce Act (Gas Transmission Services Input Methodologies)
Determination 2012.
· Clauses 5.1 to 5.7 of the Commerce Act (Specified Airport Services Input Methodologies)
Determination 2010.
These
determinations themselves are made pursuant to Part 4 of the Commerce Act 1986.
Key features of the determination
The
Commission has determined the following WACC parameters…
|
Parameter |
Transpower |
Vector
& GasNet |
Auckland
& Christchurch Airports |
|
Risk-free
rate (5 years) |
4.17% |
4.17% |
4.17% |
|
Debt
premium (5 years) |
1.75% |
1.75% |
1.18% |
|
Equity
beta |
0.61 |
0.79 |
0.72 |
|
Debt
issuance costs (5 years) |
0.35% |
0.35% |
0.35% |
|
Leverage |
44% |
44% |
17% |
|
Pre-tax
cost of debt (5 year) |
6.27% |
6.27% |
5.70% |
|
Cost
of equity (5 years) |
7.27% |
8.53% |
8.04% |
|
75th
percentile vanilla WACC |
7.55% |
8.35% |
8.63% |
|
75th
percentile post-tax WACC |
6.78% |
7.57% |
8.36% |
|
25th
percentile vanilla WACC |
6.11% |
6.73% |
6.66% |
|
25th
percentile post-tax WACC |
5.34% |
5.95% |
6.39% |
|
Midpoint
vanilla WACC |
6.83% |
7.54% |
7.64% |
|
Midpoint
post-tax WACC |
6.06% |
6.76% |
7.37% |
Previous WACC decisions
Some
of the Commissions’ previous WACC decisions are as follows.
|
WACC
decision applies to |
Approx
date |
Mid-point
WACC |
75th
percentile WACC |
|
Auckland,
Christchurch Airports for 2015 disclosure year |
July
2014 |
Vanilla
7.64% |
Vanilla
8.63% |
|
Vector,
GasNet for 2015 disclosure year |
July
2014 |
Vanilla
7.54% |
Vanilla
8.35% |
|
Transpower
for 2015 disclosure year |
July
2014 |
Vanilla
6.83% |
Vanilla
7.55% |
|
Wellington
Airport for 2015 disclosure year |
April
2014 |
Vanilla
7.70% |
|
|
EDB’s
for 2015 disclosure year |
April
2014 |
Vanilla
6.89% |
|
|
Powerco
gas CPP applications before 3/15 |
March
2014 |
Vanilla
5-year 7.54% |
Vanilla
5-year 8.35% |
|
Maui
pipeline (gas transmission) |
January
2014 |
Vanilla
7.64%, post-tax 6.85% |
|
|
Vector,
GasNet CPP applications before 12/14 |
December
2013 |
Vanilla
7.56% |
|
|
All
CPP applications before 30/9/14 |
September
2013 |
Vanilla
from 6.26% to 6.69% |
Vanilla
from 6.97% to 7.41% |
|
Transpower |
July
2013 |
|
Vanilla
6.85% , post-tax 6.17% |
|
Vector
gas distribution, GasNet |
July
2013 |
|
Vanilla
7.65%, post-tax 6.97% |
|
Auckland
& Christchurch airports |
July
2013 |
|
Vanilla
8.00%, post-tax 7.75% |
|
All
electricity distribution |
April
2013 |
|
Vanilla
6.83%, post-tax 6.14% |
|
Maui
pipeline (gas transmission) |
February
2013 |
|
Vanilla
7.46%, post-tax 6.80% |
|
All
gas distribution and gas transmission DPP’s |
December
2012 |
|
Vanilla
6.63% |
|
Vector,
GasNet CPP’s |
December
2012 |
Vanilla
6.39% (5 years) |
|
|
Powerco
gas distribution |
October
2012 |
Vanilla
6.83%, post-tax 6.12% |
|
NZ – proposed change to the WACC
determination date
Introduction
The
Commerce Commission recently released a consultation paper proposing to amend the Input Methodologies (IM) that set the date that the WACC
is determined for electricity distribution Default Price Paths (DPP’s) and for Transpower’s Individual Price Path (IPP). This is a
continuation of the Commission’s work on determining the most appropriate WACC
percentile.
Legal framework
The
legal framework for the amendments consists of the…
· Electricity Distribution Services Input Methodologies Determination 2012 (“NZCC 26”).
· Transpower Input Methodologies Determination 2012 (“NZCC 17”).
Both
of these IM’s are made pursuant to Subpart 3 of Part 4 of the Commerce Act 1986.
Proposed amendments
The
Commission proposes to amend the date by which it must determine the WACC for
electricity DPP’s and for Transpower IPP’s from 30th September to 31st
October. The following detailed amendments are proposed…
· Various sub-clauses of clause 4.4 of
the electricity distribution IM are amended to read 5 months, not 6.
· Various sub-clauses of clause 3.5 of
the Transpower IM are amended to read 5 months, not 6.
Next steps
The
Commission has consulted on this issue and expects to reach its Final Decision
in this matter by 30th September 2014 and a Final Decision on the
WACC percentile by 31st October 2014.
Global
Global – possible impact of the ISO 37120
standard
Introduction
Over
the years Pipes & Wires has observed that many local governments are
placing increasing expectations and obligations on electric companies (whether
local government owned or not) to contribute to sustainable development of communities.
This article briefly notes the development of ISO 37120:2014 which provides indicators for city
services and quality of life, and considers how that standard might impact on
electric company operations.
How ISO 37120 might effect electric
companies
ISO
37120 covers 17 aspects of urban development. Energy is obviously 1 aspect that
will effect electric companies, however it is possible that other aspects will
also effect electric companies…
· Economy – electric reliability in support
of economic growth.
· Environment – planning of large
structures such as generation plants, transmission lines and substations.
· Finance – dividends paid to the city by
a Muni.
· Fire & emergency response – ability
to restore electric supply after a disaster or civil emergency.
· Safety – safety of electrical
equipment.
· Wastewater – sustainability of
electricity used for processing and pumping.
· Water supply – sustainability of
electricity used for processing and pumping.
The specific indicators around energy
The
energy indicator has 7 sub-indicators as follows…
|
Core
indicators |
7.1 |
Total
residential electrical energy used per capita (kWh/year). |
|
7.2 |
Percentage
of city population with authorized electrical service. |
|
|
7.3 |
Energy
consumption of public buildings per year (kWh/m2). |
|
|
7.4 |
Percentage
of total energy consumed derived from renewable sources |
|
|
Supporting
indicator |
7.5 |
Total
electrical energy use per capita (kWh/year). |
|
7.6 |
Average
number of electrical interruptions per customer per year |
|
|
7.7 |
Average
length of electrical interruptions. |
Electric
companies might prima facie be held
responsible for sub-indicators 7.4, 7.6 and 7.7, however it is always possible
that the world of local government might simply expect electric companies to
influence and be responsible for all 7 sub-indicators (and quite likely without
being paid for it).
Possible responses by electric
companies
Electric
companies might consider the following pre-emptive responses…
· Ensuring that investor-owned electric
companies are fairly compensated for costs or lost revenue resulting from any
changes in urban policy eg. increased undergrounding of lines and substations.
· Ensuring that Muni’s inform their
owners of the likely impact on future dividends if they are required to create public
policy outcomes.
· Ensuring that local governments are
fully informed of the costs and security of supply implications of increased
renewable generation.
· Ensuring that urban policy doesn’t
impact on supply reliability or restoration eg. requiring an arborist to be
present before cable repairs can commence, or allowing fault trucks to drive in
emergency lanes.
· Assisting local government to
understand public building energy efficiency issues, and the likely costs.
· Ensuring that local government
understand that electric companies must recover the costs of new reticulation
assets (sub-indicator 7.2).
North America
US – regulating the “build or buy”
decision
Introduction
Excessive
capacity in any market has the potential to depress prices, dilute returns and
potentially threaten genuine long-term investment. This article examines a
request for a state regulator to intervene in a “build or buy” decision on the
side of “buying” existing generation capacity.
The factual position
Duke Energy Florida has sought approval from the Florida
Public Service Commission (PSC) to build 2,200MW of new gas fired generation by 2018,
including a new 1,640MW station and 560 MW of peaking generation at the
existing Crystal River site. This proposed new capacity will
meet expected load growth and off-set the closure of the 860MW #3 nuclear unit and 2 of the 4 coal-fired units, all
at Crystal River.
In
accordance with state law, Duke called for tenders for the construction of the
new plants. Duke itself also tendered for the work, and was the successful
tenderer.
The request for intervention
As
part of Duke’s approval to build the new generation capacity, the following
companies have intervened in Duke’s application…
· Calpine
Construction Finance.
· NRG
Florida.
· EFS Shady Hills.
All
3 of these parties own generation and are arguing that Duke should either buy
their plant (Calpine) or enter into long-term electricity supply contracts.
Calpine in particular is keen to sell its 10 year old 550MW combined-cycle plant at Osprey in central Florida which was built in
anticipation of high growth rates that never quite emerged, with consequently
diluted returns.
Duke’s arguments
Duke
has inter alia argued that…
· Because Osprey is now 10 years old, it
will be less efficient than the new generation proposed by Duke.
· Additional transmission grid investment
would be required to transmit Osprey’s generation to Duke’s retail market,
whilst Crystal River is already within Duke’s retail market.
Possible regulatory responses
The
PSC’s responses are limited to either approving or disallowing Duke’s (self-)
build option ... it cannot instruct Duke to buy existing plant or to buy
long-term generation contracts. The PSC will be considering Duke’s application
over the next few months, so Pipes & Wires will check back to see what
answer they came up with.
US – Dynergy agrees to buy generation
plants
Introduction
Pipes
& Wires has closely followed recent mergers in the US power industry (refer
below). This article examines the recent news that Dynergy has agreed to buy 12,500MW of coal and
gas-fired generation from Duke
Energy and from Energy
Capital Partners.
Recent deals
Recent
big deals in the US include…
|
Deal |
Dimensions
of merged entity |
Consideration |
Status |
|
PPL’s acquisition of LG&E and
KU (from E.On US) |
20,000MW
of generation, 2,600,000 electric customers |
$5.6b
cash and $800m debt |
Completed
in November 2010. |
|
First Energy Corp acquires Allegheny Energy |
23,700MW
of generation, 6,000,000 electric customers, annual revenue of $16b. |
$4.4b
in stock and $3.8b debt |
Completed
in February 2011. |
|
Northeast Utilities acquisition of NStar |
3,000,000
electric and 505,000 gas customers, annual revenue of $8.4b. |
$4.17b
in stock |
Completed
in April 2012. |
|
Duke Energy’s acquisition of Progress
Energy |
56,000MW
of generation, 7,100,000 electric customers. |
$13.8b
in stock and $12.2b debt |
Completed
in July 2012. |
|
|
Annual
revenue of $19b, 970,000 electric customers. |
$3.5b
cash |
Completed
in December 2011. |
|
Exelon’s bid for Constellation |
44,000MW
of generation, 6,600,000 electric customers, annual revenue of $33b. |
$7.7b
in stock |
Completed
in March 2012. |
|
About
9,800,000 customers |
$6.8b
in cash. |
Regulatory
applications in progress as of August 2014. |
Dynergy’s existing footprint
Dynergy’s
existing footprint includes 13,120MW of generation plants in California, Pennsylvania, Illinois,
New York and Maine. These plants operate within 5 separate ISO jurisdictions
(Mid-West, New England, New York, PJM and California).
The proposed generation acquisitions
Dynergy’s
proposed generation acquisitions include…
· Duke Energy’s retail electric business
in Ohio, Pennsylvania and Michigan, along with 6,100MW of generation capacity
within the PJM’s footprint. The consideration will be
$2.8b.
· Energy Capital Partners 6,300MW of
generation capacity within the New
England ISO and the PJM footprints. The consideration will be $3.45b.
These
acquisitions will expand Dynergy’s generation capacity to 25,500MW.
Possible strategies
Possible
strategies behind Dynergy’s acquisitions include…
· A sharp increase in wholesale prices in
the New England ISO as the withdrawal of about 3,100MW of generation capacity
by 2017 is announced, with only 600MW of demand response being available.
· A change in the PJM rules requiring
generators to be capable of sustained, reliable performance in the face of cold
winter weather.
Both
of these market issues have led to expected increases in wholesale prices,
prompting investment. Dynergy expects both deals to be completed by the end of
March 2015.
US – progress on the Exelon – Pepco
deal
Introduction
Pipes & Wires #134 examined Exelon’s proposed acquisition of Pepco, and noted that a range of regulatory
approvals were being sought. This article quickly re-caps the deal and examines
progress on those approvals.
A bit about Exelon and Pepco
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.
If
the merger is successful, the combined electric and gas companies will supply
about 9,800,000 customers.
Key features of Exelon’s offer
Exelon
has made a $6.8b all-cash offer of $27.25 per Pepco share, which represents a
24.7% premium to Pepco’s closing price on the announcement day.
The required approvals
The
following regulatory approvals are currently being sought…
|
Regulator |
Current
status of approval |
|
Federal Energy Regulatory Commission. |
Application
filed on 30th May. |
|
District of Columbia Public Service
Commission. |
Application
filed on 18th June. |
|
Delaware Public Service Commission. |
Application
filed on 18th June. |
|
Maryland Public Service Commission. |
Application
filed on 19th August, approval may take up to 15 months. |
|
New
Jersey Board of Public Utilities. |
Application
filed on 18th June. |
|
Virginia
State Corporation Commission. |
Commission
staff recommended on 18th August that the merger proceed subject
to 2 conditions (mainly around regulatory reporting, which Pipes & Wires
would’ve thought were a given anyway). |
Pipes
& Wires will revisit this deal as the various approvals emerge … could take
a while though.
UK & Europe
UK – the RIIO-ED1 Draft Decisions
Introduction
The
UK gas & electricity regulator OFGEM recently announced its Draft Decisions that will apply to the 14 electricity
distribution licenses in England, Wales and Scotland for the 8 year period
commencing on 1st April 2015. This article summarises those Draft Decisions.
Assessing the DNO’s business plans
Each
of the 6 distribution network operators (DNO’s) submitted a business plan for
each of its distribution licenses setting out the customer and regulatory outcomes
it proposed to deliver for the 8 year control period.
In
November 2013 OFGEM fast-tracked approval of Western
Power Distribution’s 4 business plans (South Western, South Wales, Midlands and
East Midlands) as they were judged to provide customers with sufficient value
for money. The business cases presented by …
· Electricity
North West (North Western)
· Northern
Power Grid (Northern and Yorkshire)
· UK
Power Networks (London, Eastern and South Eastern)
· Scottish
& Southern (Scottish Hydro and Southern)
· SP
Energy Networks (Scottish and MANWEB)
were
returned for further work due to deficiencies in areas such as cost
efficiencies, process weaknesses and risk allocation.
Key features of the Draft Decisions
Key
features of the Draft Decisions include the DNO’s identifying cost savings of
£700m with OFGEM disallowing a further £1.4b of costs. The total costs for the
8 years and the expected average annual bill reduction are shown for each DNO
below…
|
DNO |
Total
spend for 8 years |
Spend
per line km |
Spend
per customer |
Average
bill decrease |
|
Western
Power Distribution |
£7.1b |
£22,591 |
£917 |
£9 |
|
Electricity
North West |
£1.8b |
£25,700 |
£758 |
£26 |
|
Northern
Power Grid |
£2.9b |
£23,859 |
£750 |
£13 |
|
UK
Power Networks |
£6.0b |
£25,829 |
£739 |
£5 |
|
Scottish
& Southern |
£3.4b |
£18,589 |
£909 |
£20 |
|
SP
Energy Networks |
£3.2b |
£20,494 |
£916 |
£12 |
Next steps
OFGEM
is currently consulting on these Draft Decisions and expects to publish its
Final Decisions in November 2014.
Australia
Queensland – reconciling solar with
distribution pricing
Introduction
Recently
I’ve encountered a couple of articles discussing the dilemma facing electric
companies who have increasing amounts of rooftop solar connected to their
networks but are required to recover the fixed costs of that network on a nett
kWh basis ... certainly not a new theme, but coming at what seems to be a
quickened pace. This article picks on a recent change in distribution pricing
methodology in the Australian state of Queensland as a starting point for exploring
pricing issues.
The new pricing scheme
The
new pricing scheme approved by the Queensland
Competition Authority (QCA) in June 2014 will inter
alia remove the $0.082 feed-in tariff, and will instead enable rooftop
solar owners to negotiate the price that they will be paid for exported
electricity. The solar industry is understandably concerned about the removal
of the feed-in tariff, and that is what appears to get the media attention.
Thinking through the issues … beating
that same old drum … again !!
It
seems that underneath this there is a determined unwillingness to accept that
one way or another a distribution network that recovers its high fixed costs
with nett kWh prices provides a subsidy for those who import (consume) fewer
kWh from the network. An argument raised by the solar energy industry is along
the lines of “if more and more people reduce their demand for electricity, are
they (the distribution companies) going to increase their costs even more next
year and the year after ?” The short answer is “no” … they won’t be increasing
their costs. What they might be increasing is their prices to
recover those costs, interestingly enough as a result of increasing rooftop
solar penetration.
Some possible policy directions
It
would therefore seem that we need some clear policy direction from government
on the following issues…
· An acknowledgement that distribution
networks have a high fixed cost that is almost totally independent of kWh
throughput.
· That recovering those high fixed costs
on a kWh (variable) basis is economically inefficient, and whilst it worked
well enough when almost all customers imported from the network, the prices
necessary to recover those costs from a declining kWh consumption will have to
increase.
· Whether electric companies can adopt a
more analytically sound approach of fixed prices, and if they can’t, a clear
policy statement acknowledging that some other (economically inefficient)
approach is preferred.
· Whether subsidies are acceptable or
not. Given that subsidies for the oil and nuclear industries are apparently no
longer acceptable, maybe we need to ask why subsidies for renewables are
acceptable.
· If it is considered that subsidies for
renewables are acceptable, then who should pay those subsidies ? The policy
makers seem silent on this one, with the practical effect being that those
electric consumers who don’t generate their own electricity are simply left paying
a subsidy to those who do.
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.
Recently released book “Small
Hydroelectric Engineering Practice”
Well-known
hydroelectric engineer Bryan Leyland has recently published a book entitled
“Small Hydroelectric Engineering Practice”. This is a comprehensive reference
book covering all aspects of identifying, building and operating hydroelectric
schemes between 500kW and 50MW. Pick here for more details.
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...
· Fundamentals of the NZ
Electricity Industry – Wellington, 23rd – 24th
September 2014.
· Fundamentals of the NZ
Electricity Industry – Auckland, 7th – 8th
October 2014.
· Africa Oil & Gas Expo –
Johannesburg, 9th – 10th October, 2014.
Utility
Consultants takes no responsibility for the content of individual courses or
conferences, nor for any administrative or travel arrangements.
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.
· 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.
Utility
Consultants Ltd accepts no liability for action or inaction based on the
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