From the
editor’s desk…
Welcome
to Pipes & Wires #154. This month includes a look at a couple of topical gas
pipeline issues in New Zealand, and then also looks extensively at the
unfolding regulatory and commercial landscape around solar and microgrids.
In
amongst all this we examine a transfer of regulatory jurisdiction in Australia,
and some wider energy policy issues including closing coal and bringing back
nuclear. So … until next month, happy reading…
Recent client projects
Utility
Consultants has been involved in the following client projects…
Advice on commercial
and regulatory trends
· Client – equipment vendor.
· Location – New Zealand.
· Project – this project involved advising an equipment
supplier on the emerging electricity distribution commercial and regulatory
trends in the US, how those trends are impacting on solar and battery suppliers
and how those trends might translate into the NZ context.
Advice on optimum
maintenance resource structures
· Client – hydro and wind generation.
· Location – northern Europe.
· Project – this project involved video conferencing with a
client to help them understand the different structural arrangements of
maintenance staff and contractors and how those arrangements could create value
in terms of improved generator availability, improved productivity and reduced
costs. The project included alignment of maintenance policies and strategies
with the overall electricity market structure and generation operating
strategies.
Assess implications
of Code changes
· Client – electricity distribution.
· Location – New Zealand.
· Project – this project involved advising an electricity
distributor on how the proposed changes to Part 12A of the Electricity Industry
Participation Code could shift costs, benefits, risks and obligations between
electricity distributors and retailers.
Pick
to here to download a profile of recent projects, or here to contact Phil.
Mergers & acquisitions
NZ – sale of Maui pipeline completed
Introduction
Pipes & Wires #149 noted the conditional sale of the Maui Pipeline by the Shell, Todd and OMV consortium to First State
Investments for $335m. This article notes the completion of that sale following
approval by the Overseas Investment Office (OIO).
Description of the Maui Pipeline
The Maui Pipeline
is a welded steel pipeline of approximately 800mm diameter which stretches 307km from Oaonui to Huntly over some very rugged terrain on the west coast of the North Island.
The pipeline includes 6 production stations that inject gas directly into the
pipeline.
Annual gas
throughput is about 150 PJ, of which about half goes to Huntly Power Station and the Methanex plants.
Moving forward
The
Maui Pipeline will be both owned and operated by First Gas. The previously separate roles of System Operator, Technical
Operator and Commercial Operator will be integrated into First Gas’ overall
transmission business.
Regulating the pipelines
Because
the former Maui and Vector transmission pipelines were separately owned, they
were also separately regulated by separate default price paths (DPP’s). In its Gas Pipeline 2017 DPP Process & Issues Paper, the Commerce Commission expressed its initial view that
both transmission pipelines should be covered by one default price path from 1st
October 2017 to simplify regulation.
The
distribution network will be separately regulated from the transmission
pipelines, and separately from the Auckland gas network which Vector retained.
Regulatory policy
NZ – gas under pressure
Introduction
The
Commerce Commission recent published a paper on implementing the gas pipeline default price-quality paths (DPP) from 1st October 2017. This article recaps
the work to date and examines the key proposals of that paper.
Regulatory framework
The
regulatory framework is Part 4 of the Commerce Act 1984. Subpart 6 deals with DPP regulation, whilst Subpart 10 deals specifically with gas pipeline services.
Background
Several
gas distribution and transmission businesses are subject to default price paths
(DPP) which conclude on 30th September 2017. The Commerce Commission
has previously published a Process &
Issues Paper setting out how it intends to reset that DPP by May 2017
for a commencement date of 1st October 2017
Applicability of the DPP’s
The
distribution businesses covered by the DPP include…
· GasNet.
· Powerco.
· Vector (the legacy Auckland gas network).
· First Gas (the non-Auckland gas networks acquired from
Vector).
Both
the former Vector and Maui transmission pipelines are covered by 2 separate
DPP’s, and it is noted that the Commission has a preference for adopting 1 DPP
for both pipelines for the next control period due to their common ownership
(First Gas).
Key proposals of the paper on implementing matters
Key
proposals of the paper include…
· Changing the form of control for gas transmission businesses
from a lagged revenue cap to a pure revenue cap that will include a wash up
process.
· Changes to how gas distribution businesses treat
pass-through and recoverable costs.
· Introduction of a CapEx wash up recoverable cost for both
distribution and transmission businesses.
These
are the Commission’s preliminary views which are subject to confirmation
following a consultation process. Pipes & Wires will comment further once
the final decisions arise.
Aus – transferring regulation of Western Power to the AER
Introduction
Pipes & Wires #142 examined the announcement by Energy Minister Dr Mike Nahan that jurisdiction for regulating Western Power’s transmission and distribution networks would be transferred
from the (WA) Economic Regulatory Authority to the Australian Energy Regulatory (AER). This article examines 3 Bills introduced to
Parliament during June 2016 to give effect to this transfer of regulatory
authority.
Introducing the proposed legislation
The
Barnett Government has introduced the following 3 Bills into Parliament…
· National Electricity (Western Australia) Bill 2016.
· National Gas Access (WA) Amendment Bill 2016.
· Energy Legislation and Repeal Bill 2016.
The effect of the proposed legislation
The
key effect of the proposed legislation is to…
· Make the National Electricity Law, as set out in the National Electricity (South Australia) Act 1996, applicable to Western Australia. This has the further
effect of making any regulations pursuant to Part 4 of that Act applicable in
Western Australia.
· Make the National Gas Law, as set out in the National Gas (South Australia) Act 2008, applicable to Western Australia. Similar to electricity,
this Act will also make regulations applicable to Western Australia.
· Make minor amendments to a wide range of other related
legislation to ensure consistency.
Status of the Bills
All 3
Bills have been referred to the Standing Committee on Uniform Legislation and
Statutes Review. Pipes & Wires will comment further as the Bills progress
through the legislative process.
Solar, batteries & micro grids
US – pushing back against the rooftop solar tariff
Introduction
There
doesn’t seem to be any let up in the struggle between the rooftop solar
industry which consistently opposes any shift in the tariff mix, and electric
companies who insist that rooftop solar tariffs are necessary to prevent
subsidies from non-solar customers. This article examines a recent push back in
Texas and New Mexico.
El Paso Electric’s proposed solar tariff
Part
of El Paso Electric’s (EPE) most recent rate case (regulatory proposal)
application included a proposed $11 per month rooftop solar charge along with a
credit of 1.375c / kWh generated against their monthly bill.
The various viewpoints on the proposed tariff
The
various viewpoints include…
· EPE stated that the purpose of the charge was to recover the
cost of grid connection and usage when solar panels are not generating, and to
ensure that customers without solar are not subsidising customers with solar.
· Eco El Paso (a solar advocacy group) has acknowledged that the utility
company isn’t doing this to punish, but that it does create a disincentive.
· The Texas Public Utilities Commission (PUC) instructed EPE to re-issue its notice of the proposed
tariff increase, allowing effected customers to participate in the rate case
decision process. This will delay the effect of the tariff increase sought by
EPE.
· The New Mexico Public
Regulation Commission approved a tariff increase of $1.1m, much less than both the
$8.6m originally sought by EPE and the $6.4m sought in EPE’s revised rate case.
What should we make of this ??
How
much real insight and understanding of the issues do the various stakeholder
responses reveal ?? My observations are as follows…
· EPE’s responses seem to adequately reflect the true cost of
operating the network. Their intention to file a further rate case in 2017 to
recover further investment costs validates this.
· To their credit, Eco El Paso’s comments are starting to head
in the right direction. The next step will be for them to acknowledge the way
in which rooftop solar shifts the recovery of costs from the network.
Pipes
& Wires will comment further as the regulatory decisions emerge.
US – the regulatory framework around microgrids
Introduction
Microgrid
technologies are advancing rapidly, possibly a bit too rapidly for the existing
regulatory frameworks and decision making processes. This article examines a
microgrid proposal by Baltimore Gas & Electric (BG&E) that ran into some regulatory difficulties.
What exactly is a microgrid ?
A
microgrid is essentially a sophisticated electricity system that operates at a
smaller scale than the large electric grids we know and understand well. A key
feature of microgrids is the real-time balancing of demand with supply,
including during electric company grid blackouts. Advances in both small-scale
generation technologies and microprocessor control technologies have lifted
microgrids from a simple emergency diesel generator activated by a relay to new
and sophisticated heights.
Most
readers will have probably already spotted a couple of key features of
microgrids…
· The possibility of back-livening the electric company’s
network. Most electric companies require any embedded generation to be clearly notified
at the connection point to their network, and for that generation to
automatically disconnect and remain disconnected during a network outage.
· The fact that microgrids involve generation may encroach on
any vertical disaggregation requirements of generation from networks.
BG&E’s proposal
BG&E proposed to install microgrids at 2 village centers that included facilities such as
clinics, pharmacies, grocery stores and gas stations for which continued supply
during a grid blackout would be useful ... the capacity of the proposed
microgrids was about 2MW to 3MW each, and would’ve cost about $16m. In late
2015 BG&E filed a proposal with the Maryland Public
Service Commission (PSC) that included a charge of 4c per month to recover the
cost of the microgrids.
The opposing arguments
Opposing
arguments have come from a couple of different directions…
· Competing electric companies, who claim (quite rightfully on
the face of it) that embedding generation undermines the competitive nature of
electricity supply and the separation of networks and energy.
· The Microgrid
Resources Coalition, who claim that a narrow focus on microgrids providing
blackout resilience risks ignoring wider public benefits, primarily customer
empowerment.
The Maryland PSC’s response
The
PSC’s response has included the following…
· Recommending a wider investigation into microgrid policy.
· Questioning whether the proposal (presumably the inclusion
of generation) is legal in Maryland.
· Doubts about whether the public benefits are sufficient to
justify funding via an additional monthly tariff.
Unpacking the issues – the editor comments
A
couple of issues present themselves here…
· Microgrids, by definition, require the embedding of
generation into a network which is likely to contravene the underlying
principle of vertical disaggregation in many jurisdictions (separating networks
and energy). So any progress with microgrids will require a fundamental
re-think on the prohibition of network companies owning generation.
· The Maryland PSC has previously cast doubt on the benefits
of BG&E’s smart metering proposal. Readers might remember that BG&E’s
smart metering proposal was broadly consistent with Maryland’s energy policy,
however when presented with a rate to recover the costs, the PSC concluded that
the benefits were largely indirect, highly contingent and a long way off, and
rejected the rate case (Pipes & Wires #93 and #94).
Microgrids
have at least some potential to benefit customers, however a couple of changes
will need to occur…
· A clear policy decision around vertical disaggregation will
be required. Either we relax the existing regulatory framework to allow network
companies to also own generation (and probably compensate retailers), or we
continue to prohibit networks from owning generation. Either way, policy
settings in which the only party that is incentivised to do something is also
prohibited from doing that very thing simply won’t work.
· Regulators will need to provide clearer ex-ante statements
on what emerging technologies they will allow cost recovery from so that
electric companies don’t waste time on proposals that will be rejected.
US – rebalancing tariffs and the impact on rooftop solar
Introduction
The
clamor around how rebalancing tariffs in favor of higher fixed charges and
lower variable (kWh) charges discourages rooftop solar shows no signs of going
away anywhere in the world. This article examines a recent rate (tariff) plan
filing by Xcel Energy Colorado.
Xcel’s proposed rate plan
Xcel’s
proposed rate plan included the following components…
· A monthly network connection charge, which would range from
$2.62 for customers using less than 200 kWh per month to $44.79 per month for
customers using more than 1,401 kWh.
· A reduced energy charge of 3.37c per kWh, down from 4.6c per
kWh
Xcel
estimates that 736,000 of its 1,170,000 customers will have a reduced monthly
bill (assuming that their consumption patterns stay the same).
The impact on solar
The
benefit of rooftop solar comes in two forms…
· Avoiding the cost of importing kWh from the local network.
· Being paid for exporting kWh to the local network (which is
often regulated in the form of a feed-in tariff).
Both
forms of that benefit depend heavily on the price of a kWh, and it is readily
apparent that reducing the price of a kWh reduces the benefits of rooftop solar.
It is this reduction in benefits that the solar industry and its customers are
so upset about.
The impact on the network business
The
key issue is that the cost of operating a network is almost totally fixed, and
independent of the kWh distributed.
The
mix of fixed and variable tariffs that most electric companies use to recover
their costs are based on some legacy kWh consumption (about 8,000kWh in New
Zealand). Significant reductions in kWh consumption (such as what occurs when
rooftop solar is installed) obviously reduce that recovery of costs. The
options available to the electric company are…
· Accept a reduced revenue, leading to under-funding of each
of the building blocks.
· Increase its variable charges. That means that customers
with solar benefit even more, encouraging more customers to install solar and
further reducing the kWh-based revenue. Meanwhile customers without solar or
who can’t afford to install solar simply pay higher kWh charges (noting that
many of these customers also cannot practically reduce their kWh consumption).
· Increase its fixed charges. This cannot be avoided by solar
customers as an increase in variable charges can be, hence it reduces the
subsidy that is observed to occur when variable charges are increased.
An economic perspective on tariff rebalancing
Much
is made these days about the economic efficiency of electricity tariffs. So
let’s apply a few economic principles and see how the tariff rebalancing stacks
up…
· Ramsey pricing - demand for network connections is fairly
inelastic, hence network connection should carry most of the margin.
· Cost-reflective pricing - costs are pretty much fixed and
independent of kWh consumption, so prices should be as well.
· Dynamic efficiency - given that kWh consumption is likely to
decline, realigning the business model away from variable charges would seem to
be dynamically efficient.
So
from an economic efficiency perspective, it would appear that rebalancing of
fixed and variable charges in favor of fixed charges is analytically sound.
Regulatory decisions
NZ – determining the WACC for First Gas
Introduction
The Commerce
Commission recently released its cost of capital decision for any customised price-path (CPP) proposal made by First Gas for its gas transmission services prior to the next CPP WACC
Determination in June 2017. This article examines the key features of that
determination.
Regulatory frameworks
The regulatory
framework is set out in clauses 5.3.18 to 5.3.25 of the Gas Transmission Services Input Methodologies Determination 2012.
Key features of the gas transmission WACC’s
Key features of
the gas transmission WACC’s include…
|
|
3 year |
4 year |
5 year |
|
Mid-point Vanilla WACC |
5.78% |
5.82% |
5.87% |
|
67th percentile Vanilla WACC |
6.31% |
6.35% |
6.39% |
NZ – Orion’s transition back to a DPP
Introduction
The
Commerce Commission has recently released its Draft Electricity Distribution Services Default Price-Quality Path
Amendment Determination 2016. This sets out the Commission’s draft decision to
transition Orion from its current Customised Price Path (CPP) to the operative
Default Price Path (DPP) on 1st April 2019. This article examines
the background to Orion’s CPP, and the key features of the draft decision.
Background to Orion’s CPP
The
background to Orion’s CPP is as follows…
· Along with the other non-exempt electricity distribution
businesses (EDB’s), Orion was subject to the DPP that applied from 1st April 2010 to 31st March
2015.
· Less than 1 year into that DPP a magnitude 6.3 earthquake struck Christchurch on 22nd February 2011, wrecking much of Orion’s
network in the CBD and eastern suburbs. The cost of rebuilding the network was
beyond what the DPP was able to fund.
· Orion sought an exemption from its DPP by way of an Order In
Council as part of a wider body of earthquake recovery legislation, however
that request for such an OIC was unsuccessful. Orion were instead told they
could apply for a CPP, and moreover that CPP would need to be applied for
within the prescribed 2 years following the earthquake (ie. by 22nd
February 2013).
· Orion duly applied for a CPP that inter alia requested $155m of CapEx over and above pre-earthquake
forecasts.
· The Commission released its Final Decision on 29th
November 2013 (refer to Pipes & Wires #129 for the full story).
· That CPP applies to Orion from 1st April 2014
until 31st March 2019, and runs in parallel with the 1st April 2015 – 31st March 2020 DPP that applies to the other non-exempt EDB’s.
Regulatory framework
The
regulatory framework is Subpart 6 of Part 4 of the Commerce Act 1986, which sets out the requirements for both DPP’s and CPP’s.
In particular, s53X sets out what happens at the end of a CPP…
· The regulated supplier becomes subject to the DPP that
applies to other similar regulated suppliers.
· The starting prices for the DPP are the prices applying at
the end of the CPP unless the Commission gives at least 4 months’ notice that
different prices will apply.
· The regulated supplier remains subject to the prevailing DPP
until either the end of that DPP or a new CPP is sought and granted.
The Commission’s proposed transition back to a DPP
Key
features of the Commission’s draft decision include…
· Unless Orion seeks another CPP, it will transition from its
CPP to the (amended) DPP on 1st April 2019 and be subject to that
DPP for the remainder of its term (until 31st March 2020).
· The expectation that Orion will start the DPP at the same
prices it ends its CPP with, excluding any claw back, but with a CPI
adjustment.
· The Commission expects to announce its Final Decision in
October 2016 after a period of consultation.
The
precise legal mechanism is a (draft) amendment to the 2015 – 2020 DPP
Determination. Pipes & Wires will comment further once the Final Decision
is released.
Energy policy
UK – accelerating the closure of coal-fired generation
Introduction
Whether
the closure of fossil-fired generation will cause the lights to go out has
become a hotly disputed topic around the world, with various factions of the
green movement claiming that the risk of blackouts has been over-stated by
fossil-fired generation operators. This article examines a recent call for the
UK to close its’ remaining coal-fired generation by 2023 and questions whether
the proposed substitution with gas-fired generation and interconnection is wise.
The call to close coal-fired generation
A
recent report by liberal conservative think tank Bright Blue entitled “Keeping the lights on: security of supply after coal” has called for the UK to close its remaining coal-fired
generation by 2023 rather than 2025. The report is based around 3 scenarios…
· A base case, in which renewables, nuclear and interconnector
capacity increase largely in line with market expectations. Key features
include Hinkley Point C opening 3 years behind schedule in 2029, all remaining coal-fired
generation closing at the end of 2025, and increased purchase of capacity under
the Capacity Market from 2020 to about 2025.
· A low risk scenario, in which renewables, nuclear and
interconnector capacity exceeds market forecasts, and demand falls. Hinkley
Point C is completed in 2026, whilst all remaining coal-fired generation is
forced to close by the end of 2025 or possibly earlier as its viability
declines.
· A high risk scenario in which demand increases but new
capacity increases are less than forecast. Hinkley Point C doesn’t proceed and
all remaining coal-fired generation is closed by 2020.
The
reports’ overriding conclusion is that the lights will stay on, even under the
high risk scenario. However that is underpinned by the need to commission somewhere
between 8,000MW and 21,000MW of gas-fired generation by 2030. The report inter alia recommends that the previous
coal-fired generation phase-out date of 2025 should be bought forward to 2023,
and that a CO2 emissions performance standard be used to regulate
coal-fired generation out of the market.
The proposed substitution of gas for coal
Under
the broad theme of examining the UK’s declining reserve capacity margin (Pipes & Wires #116, #143 and #148), the increasing dependence on imported gas from Europe and
the declining security of that gas supply was noted. It is not clear that this
situation has eased significantly enough to make any gas-fired generation that
is built useful.
The proposed increase in interconnection with Europe
Proposals
to interconnect the UK with Europe by (additional) undersea cables raises the
following issues…
· Possible declines in reserve capacity margins in the
countries that the UK might interconnect with.
· The possibility that those interconnects will simply import
coal-fired electricity from Europe. That presents the same moral dilemma that
Germany faced when on the one hand it decided to close its nuclear stations,
but on the other hand kept importing nuclear electricity from France and the
Czech Republic.
Wider supply-side issues in the UK
Some
of the wider supply-side issues in the UK include…
· The closure of 14 nuclear generators totaling 7,680MW by the
end of 2030.
· The difficulties of getting new nuclear generation
confirmed, including the range of difficulties still hanging over Hinkley Point
C before EDF will commit to construction.
· The plant most likely to be purchased by the Capacity Market
will be diesel generators, which will be way more polluting than coal-fired
generation.
The editor comments
An
analysis of the proposed alternative electricity supplies suggests many
additional and increasingly complex risks, mainly associated with plugging into
Europe’s gas or electricity. It is not clear that current policy is providing
strong enough investment signals for the emerging gap to be closed.
Sweden – bringing back nuclear
Introduction
Many
countries are well down the path of phasing out their nuclear generation, with
Sweden being among those furthest along that path. This article investigates
the somewhat surprising decision by the Riksdagen to bring back nuclear generation.
Sweden’s progress on phasing out nuclear
Following
the Three Mile Island accident in 1979, an advisory referendum was presented to the Swedish people
in March 1980. The 3 options presented to voters were actually quite complex
and multi-dimensional, and while they embodied preferences for migrating to
renewable energy and improving energy conversation, option #3 arguably clouded
the issue of nuclear electricity by including nuclear weapons. Notably, there
was no option to continue or expand the use of nuclear power, so essentially
the referendum was about how quickly nuclear power should be phased out rather
than whether it should continue or be phased out. Presumably those who
supported nuclear power didn’t get a voice.
Based
on voter preferences, the Riksdagen declared that no additional nuclear stations
would be built, and that all 12 of the then operational nuclear stations should
be closed by 2010 (as it was considered that most of the stations would have
remaining lives of about 25 years).
Pressure
to accelerate the closures increased after Chernobyl (1986), and in 1988 the Riksdagen decided that the closures should
begin in 1995. This decision was over-turned in 1994 due to pressure from the
trade unions.
Overtime
there has been jockeying amongst the minor political parties, of which the most
significant result was a multi-party agreement to close the two 600 MW boiling
water reactors at Barsebäck (which occurred in 1999 and 2005 respectively) but to
reprieve further closures until 2012 to 2025.
The
current closure program is for Oskarshamn #1 and Ringhals #1 and #2 to close over the next 1 to 3 years, but for 6 other
reactors to remain open until at least 2013.
The proposed return of nuclear
A
recent agreement signed by the current government and opposition parties includes
the following…
· A phase out of the tax on nuclear electricity that was
introduced in 1984 and is currently €7.5 per MWh (which generates annual tax
revenues of about €465m).
· Allowing the construction of up to 10 new nuclear reactors to
replace aging reactors.
· A target of 100% renewable energy by 2040 (which is clearly
underscored as a goal, and not as a final cut-off date for the nuclear
generation).
Just
as a comment, the emerging picture is that a nuclear station takes between 12
and 15 years to plan, approve, design, build and commission, and then might be
expected to operate for 40 years to fully recover its costs. So a station
approved today (and commissioned in 2030) would be expected to operate for
about 30 years beyond the 100% renewable target date. It seems unlikely that
there won’t be at least some pressure for early closure which will undermine
the investment incentive.
UK – investigating the competitiveness of energy supply
Introduction
In
March 2014 Ofgem concluded that competition in the UK’s retail energy
markets wasn’t working as well as it should, and referred the matter to the Competition & Markets Authority (CMA) to investigate. This article follows on from the
CMA’s provisional findings that were discussed in Pipes & Wires #153 with an examination of the CMA’s final report.
Scope of the investigation
Just
to recap, the investigation focused on the following possible causes of adverse
effects on competition (AEC’s)…
· Opaque prices or low levels of liquidity in wholesale
markets creating entry barriers.
· Vertically integrated energy companies harming the
competitive position of non-integrated energy companies.
· Market power leading to higher prices.
· Weak incentives for energy companies to compete on either
price or non-price factors.
Comparing some
of the provisional and final conclusions of the investigation
The
following table compares the provisional and final conclusions of the
|
Issue |
Provisional
conclusions |
Final
conclusions |
|
Dispatch
of generation plant |
Generation
plant appears to be dispatched in accordance with the merit order. |
Concluded
that self-dispatch was not reducing price transparency, increasing costs or
introducing technical inefficiency. |
|
Wholesale
market prices |
Based
on an analysis of profitability, the wholesale market price does not appear
to be above competitive levels. |
Confirmed
this view. |
|
Profitability
of individual firms |
Based
on an analysis of profitability, the wholesale market price does not appear
to be above competitive levels. |
Confirmed
this view, reinforcing the view that generators do not have unilateral market
power. |
|
Transmission
location loss charges |
An
absence of strong transmission location loss charges. |
Confirmed
this absence, and noted that this will lead to both short-term and long-term
inefficiencies including the possibility of inefficient investment in
generation. |
Ofgem
has urged the industry to implement the CMA’s recommendations for further
improvement.
Industry restructurings
US – is the end in sight for the Boulder muni bid ?
Introduction
Pipes
& Wires has been following the efforts of the City Of Boulder, Colorado to
purchase Xcel Energy’s distribution assets and run those assets as a Muni (Pipes & Wires #126, #128, #137 and #141). This brief article notes the recent negotiations between
Boulder and Xcel to end Boulder’s bid to form a muni.
Where did the muni’ising process get to ?
After
seeking the citizens’ approval through two ballots, the matter ended up in the
District Court. The Court ruled inter
alia that because the breakup of Xcel’s distribution network could also
affect the supply reliability received and the prices paid by Xcel customers
outside the Boulder City limits, it was both necessary and appropriate for the Colorado Public Utilities Commission to determine how the distribution systems assets should be
allocated.
Recent happenings
In
amongst the confidential nature of the discussions, statements from both
Boulder and Xcel have indicated that more cooperation particularly with
renewable energy and customer choice appears to be a better way for Boulder to
achieve its initially stated objectives of lower prices and increased renewable
energy.
Whichever
way the negotiations end up, the balloting process could take until the end of
2017 (noting the idea of a muni was first raised in 2004). Pipes & Wires
will comment as the negotiations progress.
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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