Pipes & Wires

INSIGHT AND ANALYSIS OF COOL ENERGY & INFRASTRUCTURE STUFF

Issue 150 – March 2016

From the editor’s desk…

Welcome to Pipes & Wires #150. This issue has a focus on regulatory models and determinations in New Zealand, Australia and Italy, but in between discusses the following issues…

· A report from the nuclear fuel cycle Royal Commission in South Australia.

· A look back 30 years to what happened at Chernobyl.

· What will hopefully be the final hurdle for the Exelon – Pepco merger.

· A possible political u-turn in Western Australia that could lead to Western Power being privatised.

So … until next month, happy reading…

Regulatory decisions

Aus – Tribunal rules on recent revenue determinations

Introduction

Previous issues of Pipes & Wires examined the Australian Energy Regulator’s (AER) recent electricity and gas distribution revenue determinations for the Australian states of New South Wales and South Australia, and for the Australian Capital Territory. Pipes & Wires #146 and #148 noted the challenges to the electricity determinations by some of the applicants. This article examines the first of two outcomes of those challenges.

Legal framework for the appeals

The legal framework for the appeals are as follows…

· s71B of the National Electricity Law.

· s245 of the National Gas Law.

These appeals are the first to occur under the recently reformed limited merits review regime.

The appeals to the Australian Competition Tribunal

The appeals made to the Tribunal were…

· ActewAGL, AusGrid, Endeavour Energy and Essential Energy appealed to the Tribunal in June 2015.

· Jemena Gas Networks in June 2015.

· SA Power Networks appealed to the Tribunal in November 2015.

The basis of the appeals was that the AER had made material errors in calculating some key components of each determination.

The Tribunal’s rulings

The Tribunal’s ruled in favor of the appellants on the following issues…

· Operating expenses (OpEx).

· Some components of the allowable return on debt.

· Value of gamma.

· ActewAGL’s service target performance incentive scheme (STIPS) allowance.

The Tribunal ruled in favor of the AER on the following issues…

· Allowable return on equity.

· Some components of the allowable return on debt (noting that the transitional approach to the trailing average cost of debt was referred back to the AER).

· Efficiency benefit sharing schemes.

· Some metering issues.

Of particular significance is the Tribunal’s view that the AER must use a broader range of modelling and benchmarking to determine the allowable OpEx, including a bottom up review.

The final outcome

The Tribunal’s rulings have not resulted in a set of re-determined revenues, but rather have provided guidance to the AER on how it should re-determine those revenues. Pipes & Wires will examined those re-determined revenues as they emerge.

Aus – Court dismisses judicial review of solar tariff rejection

Introduction

Electric companies are seeking to introduce special solar tariffs to ensure that rooftop solar customers pay their fair share of the distribution charges. This article notes an attempted legal challenge over a proposed solar tariff in South Australia.

SA Power Networks’ proposed solar tariff

The Annual Pricing Proposal submitted by SA Power Networks for the 12 months commencing on 1^st July 2015 originally included a solar component, which it was estimated would cost a customer with rooftop solar about an extra $100 per year. SA Power Networks notes that a typical house with rooftop solar has an annual load factor that is about 20% less favorable than a non-solar house (hence the kWh revenue is substantially less).

The Australian Energy Regulator’s determination

On the 19^th June 2015 the Australian Energy Regulator (AER) advised SA Power Networks that inter alia its proposed Solar Tariff did not comply with Clause 6.18.4(a)(3) of the National Electricity Rules which requires customers with micro-generation to be treated no less favorably than non-generating customers with similar load profiles. In its determination, the AER said that it was not satisfied that SA Power Networks had demonstrated that solar and non-solar customers have sufficiently dissimilar load profiles.

The AER required SA Power Networks to inter alia remove the Solar Tariff from its Proposal and re-submit the Proposal within 10 working days (which it did). The AER subsequently approved the re-submitted Proposal.

The proposed legal challenge

SA Power Networks subsequently applied to the Federal Court for a judicial review of the AER’s determination. The Court dismissed that application on the basis that the AER has correctly applied the pricing principle set out in Clause 6.18.4(a)(3), and did not make a reviewable error.

The philosophical debate

Putting aside the AER’s correct interpretation of the Rules, the battle line in this (and all similar tariff disputes) is whether solar customers should be able to continue to contribute less to the distribution costs than non-solar customers due to the kWh cost-recovery mechanism. Some of the statements made in this case and in others around the world suggest that solar advocates genuinely believe they are entitled to a subsidy.

Aus – the 2016-2020 Victorian electricity revenue determinations

Introduction

The five electricity distribution businesses in the Australian state of Victoria recently submitted their Revised Regulatory Proposals to the Australian Energy Regulator (AER) for the 5 year regulatory period starting on 1^st January 2016. This article examines progress now that the Revised Proposals have been submitted.

The regulatory framework

The regulatory framework has its basis in s7 of the National Electricity Law, which states the National Electricity Objective which is inter alia to promote efficient investment in electricity services for the long-term benefit of consumers. Chapter 6 of the National Electricity Rules sets out the details for economic regulation of distribution services.

Key features of the process to date (AusNet Services)

Key features of the process to date include…

Parameter	Initial Proposal ($ nominal)	Preliminary Determination	Revised Proposal	Final Determination
Total OpEx	$1,356m	$1,191m	$1,018.8m
Total CapEx	$1,690m	$1,471.1m	$1,749.3m
Opening RAB	$3,547m	$3,423.3m	$3,444.6m
Regulatory depreciation	$478m	$368.7m	$519.2m
Unsmoothed revenue	$3,567m	$2,878m	$3,812.4m
X	0%	8.12%	8.43%, -31.74%

Key features of the process to date (CitiPower)

Key features of the process to date include…

Parameter	Initial Proposal ($ nominal)	Preliminary Determination	Revised Proposal	Final Determination
Total OpEx	$502m	$445.8m	$462.4m
Total CapEx	$848m	$659m	$825.8m
Opening RAB	$1,804m	$1,795.1m	$1,802.6m
Regulatory depreciation	$297m	$304.6m	$318.5m
Unsmoothed revenue	$1,718m	$1,413.7m	$1,572.2m
X	-3.5%	6.75% to -0.45%	6.75% to -0.45%

Key features of the process to date (Jemena)

Key features of the process to date include…

Parameter	Initial Proposal ($ nominal)	Preliminary Determination	Revised Proposal	Final Determination
Total OpEx	$499m	$390m	$471m
Total CapEx	$841.2m	$773.6m	$862.5m
Opening RAB	$1,190.8m	$1,187.0m	$1,187m
Regulatory depreciation	$243.2m	$237.7m	$264.5m
Unsmoothed revenue	$1307.7m	$1,082.3m	$1,429.9m
X	About -1%	9.2%, 8.5%, 1%	9.2%, -27%, -2%

Key features of the process to date (Powercor)

Key features of the process to date include…

Parameter	Initial Proposal ($ nominal)	Preliminary Determination	Revised Proposal	Final Determination
Total OpEx	$1,334m	$1,256m	$1,252.3m
Total CapEx	$2,006m	$1,610m	$1,783m
Opening RAB	$3,363m	$3,344m	$3,357.6m
Regulatory depreciation	$504m	$503m	$526m
Unsmoothed revenue	$3,662m	$3,086m	$3,303m
X	-3%	8%, -0.8%	8%, -0.8%

Key features of the process to date (United Energy)

Key features of the process to date include…

Parameter	Initial Proposal ($ nominal)	Preliminary Determination	Revised Proposal	Final Determination
Total OpEx	$800m	$711m	$781m
Total CapEx	$1,104m	$815m	$1,189m
Opening RAB	$2,189m	$2,052m	$2,190m
Regulatory depreciation	$640m	$315m	$660m
Unsmoothed revenue	$2,150m	$1,841m	$2,367m
X	0%	8.7%, 0%	8.7%, -15.2%

Nuclear energy

Aus – the nuclear fuel cycle Royal Commission

Introduction

Pipes & Wires #147 noted the establishment of a Royal Commission by the South Australian Government to investigate various aspects of the nuclear fuel cycle. This article briefly examines the tentative findings to provide some context for the Final Report which is due around May 2016.

The terms of reference

The Royal Commission’s terms of reference are to investigate the following 4 aspects of the nuclear fuel cycle…

· Exploration and mining.

· Processing.

· Nuclear electricity generation.

· Storage and disposal of waste.

The tentative findings

The tentative findings include…

· An expansion of Uranium mining has the potential to be economically beneficial, however it is not the most significant energy opportunity facing South Australia.

· The Uranium supply market is currently oversupplied and is expected to be uncertain for the next decade, suggesting that there would be no commercial opportunities for developing South Australia’s Uranium processing capabilities over that decade.

· Current electricity market conditions and the expected costs of nuclear power within that existing market structure would make nuclear power unviable in South Australia for the foreseeable future. However the trend towards low-carbon generation technologies means it would be wise to include nuclear amongst future electricity generation options.

· Storage and disposal of spent fuel could bring significant economic benefits to South Australia.

Given the current uncertainty around nuclear power, languishing demand growth, the political disconnect between many elements of energy policy, the difficulty of obtaining a viable price for the generated electricity and the flush of plant closures across Europe, none of these tentative findings should come as a great surprise. Pipes & Wires will comment further as the Royal Commission’s final conclusions emerge.

Ukraine – 30 years on from Chernobyl

Introduction

Next month will be the 30^th anniversary of the explosion at Chernobyl Power Station ... an event that many in Eastern Europe are still painfully reminded of. This article examines Chernobyl in detail and tries to uncover a bit more of what really happened there.

Some facts about Chernobyl power station

The station itself is 18km north-east of the city of Chernobyl, and at the time of the accident in 1986 was supplying about 10% of the Ukraine’s electricity through the 330kV and 750kV grids. Construction began in 1970 and the first 4 RBMK-1000 reactors (rated at 3,200MWt) were commissioned in 1977, 1978, 1981 and 1983 respectively. The 5^th and 6^th reactors that were under construction at the time of the accident were rapidly abandoned.

Essentially the RBMK reactor is a graphite moderated, boiling water reactor (BWR) that was derived from a plutonium-producing military reactor. A critical feature of the RBMK is that when the cooling water boils to steam, its neutron absorbing capacity drops to practically nil. This means more neutrons are available to fission the ²³⁵U nuclei, increasing the heat generation and in turn flashing more water to steam (giving the RBMK a very high positive void coefficient). A high positive void coefficient didn’t necessarily make the RBMK inherently unsafe as this runaway can take several seconds or even minutes, theoretically giving time to bring the reaction back under control.

Reactors #3 and #4 were second generation RBMK’s that had a number of improved safety features which reactors #1 and #2 did not have.

What actually happened on 26^th April 1986 ?

The accident arose from an experiment to test whether the run-down of the turbine following a trip could provide sufficient electricity for the cooling water pumps while the auxiliary diesel generators were started and synchronised. Desk-top studies suggested it would work however 3 attempts to achieve this in practice over the 3 previous years had all failed.

At 01:23 on 26^th April a 4^th attempt at the experiment began by tripping the steam from reactor #4, which was followed by a run-down of the turbine and 4 of the 8 cooling water pumps. In the 39 seconds before the diesel generators were synchronised the cooling water flow dropped sufficiently to allow voids in the cooling water circuit to form. Although this started a positive feedback cycle, automatic control of the graphite control rods successfully reduced that increased heat generation. At 01:23:40 an emergency shutdown was initiated (and whether this was manual or automatic remains debated to this day). Unfortunately the design of the reactor resulted in cooling water being expelled a few seconds before the graphite rods filled the voids, resulting in a thermal runaway which was followed a few seconds later by an explosion accompanied by the last recorded power output of about 33,000MWt (10x nominal rating). A 2^nd explosion followed, the precise cause of which remains undetermined.

Note that this was the 2^nd of 3 accidents that occurred, the first being a partial core meltdown on reactor #1 in 1981, and the third being a simple non-nuclear generator hydrogen leak on turbine #4 (associated with reactor #2).

What happened after the 26^th April 1986 ?

Seconds after the 2^nd explosion, the 2,000 ton upper plate of the reactor vessel was torn lose and blown off, and flaming material caused at least 5 separate fires on the bitumen-coated roof. Some 3 hours later at 05:00 the reactor was shut down at the instruction of the night shift superintendent.

Evacuation of the nearby town of Pripyat began at 14:00 on 27^th April, almost 37 hours after the explosion, however there was still no official word of the explosion until 3 days later on 29^th April when radiation alarms at Forsmark power station in Sweden were activated. To this day a 30km exclusion zone still exists around Chernobyl.

Mergers & acquisitions

US – progress on the Exelon – Pepco merger

Introduction

Pipes & Wires #147 noted an interesting twist to this drawn out merger in which an organisation called DC Public Power wants to convert Pepco into a public utility (after 5 out of 6 state regulators approved the merger). This article examines recent events.

DC Public Power’s approach

DC Public Power wants to convert Pepco into a public utility. DCPP’s principal arguments are that public ownership could deliver $1b of public benefits over 20 years and that keeping Pepco separate from Exelon’s generation fleet would provide a stronger pathway to distributed energy, micro-grids and energy efficiency.

Pepco and Exelon then re-iterated a wide range of merger benefits and commitments, including tariff freezes, bill credits, sharing of amalgamation benefits, new hires in Washington DC, workforce development, easier installation of rooftop solar, and a commitment to exceed reliability standards. Each of these benefits would seem to directly address the concerns motivating DCPP.

The Washington DC PSC’s recent rulings

In late February 2016 the Washington DC PSC rejected the proposed merger in a 2-1 vote, but then also voted to allow Exelon and Pepco to submit a revised proposal that would include new penalties for failing to meet service commitments. The revised proposal would need to be submitted by 11^th March.

Exelon’s response and the markets comments

Prior to the Washington DC PSC’s ruling, Exelon had indicated that it would abandon the merger if it was not fully completed by early March, which would seem to precede the PSC’s 11^th March date for submitting a revised proposal. Many commentators, however, believe that Exelon has invested too much in the merger process to date to abandon it.

Latest maneuverings

Pepco and Exelon filed an amended proposal that would specifically address the PSC’s concern of a loss of benefits for Pepco customers in Washington DC. That amended proposal included 3 options aimed at providing the PSC with the latitude to balance various interests as it sees fit.

However the Washington DC Office of the People’s Counsel said it did not believe that the proposed allocation of the $78m customer investment fund would adequately protect domestic customers. So the whole future of the merger rests on adequately resolving exactly how Washington DC domestic customers will be protected from tariff increases. Pipes & Wires will comment further as this issue progresses.

Regulatory policy

NZ – resetting the gas default price paths

Introduction

Several gas distribution and transmission businesses are subject to default price paths (DPP) which concludes on 30^th September 2017. The Commerce Commission recently published a Process & Issues Paper setting out how it intends to reset that DPP by May 2017 for a commencement date of 1^st October 2017. This article examines that Paper.

The businesses covered by the DPP’s

The distribution businesses covered by the DPP include…

· GasNet.

· Powerco.

· Vector’s Auckland gas network.

· Vector’s non-Auckland gas network

At the time of writing, Vector’s non-Auckland gas network is in the final stages of being sold to Colonial First State with approval by the Overseas Investment Office being awaited.

The transmission businesses covered by the DPP include…

· Vector.

· Maui Developments.

Both of these businesses have been sold to Colonial First State pending final approval by the Overseas Investment Office at the time of writing.

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.

Issues that the Commission is interested in

Some of the issues that the Commission is interested in receiving submissions on are…

· Forecasting revenue, including considerations of how to set the starting revenue.

· Forecasting of costs, including the preliminary view that major capital works might be best dealt with through a customised price path (CPP).

· Forecasting gas volumes.

· Estimating productivity.

· Whether the overall control should limit prices or whether it should limit revenue.

· What incentives should exist for expenditure, including the preliminary view that the complexity of an incremental rolling incentive scheme (IRIS) would outweigh the benefits.

· Whether the two transmission pipelines that will are expected to be owned by Colonial First State should be subject to a single DPP, or whether each pipeline should have its own DPP.

Pipes & Wires will comment further as the Commission continues its work.

Italy – towards a new regulatory model

Introduction

Regulation of wires businesses (and pipes businesses) has traditionally emphasised inputs with an obvious issue being the ability to accurately forecast key inputs such as capital expenditure, operating expenditure and demand growth. This article examines the Italian Regulatory Authority’s (AEEGSI) move towards an outcome based approach.

The migration from emphasis on inputs to emphasis on outcomes

As the energy sector becomes more complicated, obtaining robust regulatory outcomes has also become more difficult. To this end the British energy regulator Ofgem has implemented the RIIO regulatory model which emphasises key network outcomes such as safety, reliability and price. State regulators in the United States are also considering moving away from input based models.

Italy’s new regulatory model

The AEEGSI’s decision 654/2015 sets out a new regulatory model that will apply for the 2016 – 2023 regulatory period, with the first 3 years representing a transitional period. One of the objectives of this process is to ensure continued stability for asset owners, which AEEGSI has long recognised as important.

Key features of the new regulatory include…

· Annual tariff adjustments to reflect actual operating costs.

· Targeted productivity factors to improve allocation of efficiency gains derived from transmission, distribution and metering respectively.

· An intent to symmetrically share efficiency gains at the next reset.

· Inclusion of all efficient capital spend into the RAB with a 1 year lag.

· Basing the RAB on depreciated historical cost, inflated with a construction-specific index.

· Periodic reviews of WACC.

· Straight line depreciation based on the technical life of assets.

· An emphasis on total expenditure (TotEx) rather than treating capital expenditure (CapEx) and operating expenditure (OpEx) differently and potentially distorting investment decisions.

Pipes & Wires will comment further as the new regulatory model is implemented.

NZ – allocating risk under various control mechanisms

Introduction

The Commerce Commission recently released a paper on Emerging Views On The Form Of Control as part of the Input Methodologies (IM) Review. This article considers how the various forms of control might allocate the risk of under-recovery and over-recovery of revenue.

The risk of under or over-recovery of revenue

All forms of revenue or price control require inter alia a forecast of revenue for many years, and of course a lot can happen to an electric or gas company’s revenue during those years (for example kWh sales of electricity took a sharp dive after the global financial crisis in late 2008). In the specific context of electric and gas company’s whose costs generally don’t vary much with revenue, any under or over-recovery of revenue can lead to either unacceptably low profits or unacceptably high profits.

Hence one measure of the robustness and credibility of a regulatory regime will be how under-recovery or over-recovery of revenue is treated.

The various forms of control and how they might allocate risk

Regulated electric and gas companies are currently subject to the following forms of control…

Businesses	Form of control	Nature of risk	Size of risk	Allocation of risk
EDB’s, GDB’s	Weighted Average Price Cap (WAPC).	Volume and therefore total revenue fluctuates relative to high fixed costs.	Possibly high.	Lies primarily with the regulated company.
GTB’s	WAPC.	Volume and therefore total revenue fluctuates relative to high fixed costs.	Possibly high.	Lies primarily with the regulated company.
	“Pure” Revenue Cap (with no transfers to subsequent years).	Imbalance between fixed ex-ante revenue and costs results in either insufficient or excessive profit.	Low, probably lower than WAPC.	Lies primarily with the customers, but likely to be mitigated at next reset if claw back is available.
Transpower	Revenue Cap, but includes a mechanism to transfer certain positive or negative revenue adjustments to subsequent years.	Imbalance between fixed ex-ante revenue and costs results in either insufficient or excessive profit, however annual adjustment mechanism would further minimise this risk.	Very low	Lies primarily with the customers, but likely to be mitigated through annual adjustments and at next reset if claw back is available.

So for electric and gas companies that have a high ratio of fixed to variable costs, it appears that a Revenue Cap would arguably result in a lower risk (especially if claw back is available). An obvious concern is whether the benefits of reducing risk and risk allocation exceed the increased complexity of the form of control.

The conclusions of the above table seem to be reflected in the Commission’s emerging view that appropriate forms of control are…

· Changing to a Pure Revenue Cap for EDB’s.

· Continuing with the existing Pure Revenue Cap for GTB’s, with an amendment to wash up under and over recoveries.

· To conduct further analysis of the most suitable form of control for GDB’s

Alignment of risk allocation with the Purpose Statements

Part 4 of the Commerce Act 1986 sets out 2 purpose statements…

· At s52A, which inter alia requires promoting of long-term outcomes that encourage regulated suppliers to invest in new and replacement assets.

· At s52R, which aims to promote certainty for regulated suppliers.

Given that the RC ostensibly results in a lower risk of revenue under-recovery, it would appear that adoption of an RC is more consistent with both Purpose Statements than continued use of a WAPC.

Privatisations & structural changes

Aus – possible privatisation in the West

Introduction

Long-time readers will have some idea that Western Australia’s electricity industry is something of a political football, and regularly gets kicked from one end of the spectrum of market reform models to the other. This article examines recent announcements that the Government has little alternative to selling Western Power (the state owned poles & wires business).

Recent announcements by the Premier

Last month Premier Colin Barnett conceded that Western Power may have to be sold to boost Western Australia’s sagging commodity prices, ailing credit rating and increasing debt. This would seem to be a significant political u-turn as Barnett has previously opposed any sale of Western Power as recently as 2013 (a point that his opponents have been quick to point out).

Putting a price tag on Western Power

Whilst the State Treasurer has indicated that Western Power is “worth in the vicinity of $15b”, analysts appear to have more modest valuations of between $10b and $15b.

Likely next steps

Barnett expects that any possible sale of Western Power will be announced in the May 2016 budget, although it is widely expected that it will end up being an election issue in 2017. Pipes & Wires will pick this story up after the May budget.

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.

Conferences & training courses

The following conferences and training courses are planned...

· No events scheduled.

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…

· 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.

Cool stuff

Newly published book – “Keeping The Lights On”

Well-known electricity historian and author Helen Reilly has recently published her latest book “Keeping The Lights On – The History Of System Operations In New Zealand 1939 – 2013”. Pick here to order your copy for only $46.50 from Grid Heritage. It’s a thoroughly good read, and complements Helen’s previous book “Connecting The Country”.

House-keeping stuff

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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 contents of Pipes & Wires including any loss, damage or exposure to offensive material from linking to any websites contained herein, or from any republishing by a third-party whether authorised or not, nor from any comments posted on Linked In, Face Book or similar by other parties.