Pipes & Wires


Issue 152 – May 2016


From the editor’s desk…


Welcome to Pipes & Wires #152. This issue focuses quite narrowly on a range of happenings in New Zealand and Australia.


We start with a look at some regulatory policy amendments, and then take a critical look at the thorny issue of dry year security of supply in Tasmania and New Zealand. We then have a quick look at the conclusions of South Australia’s Royal Commission on the nuclear fuel cycle.


This issue concludes with a look at some revenue and cost of capital decisions in Australia, New Zealand and France. So … until next month, happy reading…


Regulatory policy


NZ – amending the transmission pricing methodology (TPM)




Amending the pricing of Transpower’s transmission services is one of the Electricity Authority’s (EA) on-going streams of work. This article examines the EA’s recently released second issues paper.


The importance of correct transmission pricing


The TPM defines how much each grid customer pays for its grid connection services (just to be clear, it is not about Transpower’s overall revenue which will remain between $950m per year and $1b per year until the next revenue reset). The EA is concerned that the current TPM is complex and is sending the wrong price signals to grid customers that in turn are resulting in inefficient investment at a national level.


The regulatory framework


The regulatory framework for this work is set out in Subpart 4 of Part 12 of the Electricity Industry Participation Code which sets out the requirements for the TPM. Section 12.79 includes the requirement for the EA to assess the TPM against the EA’s statutory objectives in s15 of the Electricity Industry Act 2010 which requires the EA to promote inter alia the efficient operation of the electricity industry for the long-term benefit of customers.


The existing TPM charges


The existing TPM includes 3 major charges…


·      A connection charge (about $128m per year) paid by customers who use specific grid assets.


·      An HVDC charge (about $150m per year) paid by the South Island generators.


·      An interconnection charge (about $639m per year) paid by direct customers and EDB’s for their use of the “grid at large”. The EA is concerned that the “postage stamp” nature of this nationally averaged demand-based charge does not strongly reflect the benefits provided by the grid to individual customers, nor the charges they pay.


Key features of the proposed TPM


Key features of the proposed TPM include…


·      The introduction of an “area of benefit” charge in which all parties in an area that benefit from transmission services will pay a price for those services that reflects the costs of providing those services. The EA notes that some specific new assets turn connection assets into interconnection assets, which then have their costs recovered by the less efficient interconnection charge.


·      A residual capacity-based charge that will collect the difference between the total revenue requirement and the revenue collected from the “area of benefit” charge. A key feature of the proposed TPM is the expected migration of grid services from the “residual charge” to the “area of benefit” charge over time, meaning that charges will better reflect the cost of providing grid services and therefore provide stronger incentives to avoid or defer future grid investment.


·      A widening of the criteria for seeking a prudent discount including if standalone generation would be a cheaper option or if transmission prices are creating a material risk of a direct customer closing their business (leaving stranded assets). This is expected to discourage stranding of assets by investment in local generation.


·      An optimisation feature in which grid customers can request Transpower to reduce the value of “area of benefit” assets if there has been a material reduction in the use of those assets.


The expected results


As with most changes to pricing methodologies, there will be winners and losers … the second issues paper includes a chart showing the expected $ per year per household change for each EDB. Beyond that, we might expect to see differing responses to grid investment from those of the past.


Next steps


The EA will be receiving submissions until 5pm on Tuesday 26th July 2016. For help with compiling a submission, pick here or call Phil on (07) 854-6541.


 NZ – reviewing the principles for distributed generation




The principles underpinning the prices charges to connect distributed generation to a distribution network are currently regulated. This article examines the Electricity Authority’s recently released consultation paper reviewing distributed generation pricing principles (DGPP).


The regulatory framework


The regulatory framework is set out in s6.9 of Part 6 of the Electricity Industry Participation Code, and essentially specifies a minimum pricing position if the DG operator and the EDB can’t agree on suitable terms.


The proposed removal of pricing principles from the Code


The EA is proposing to remove the DGPP from Part 6 of the Code after identifying the following concerns…


·      Limiting the charge for connecting DG to a network to the incremental cost does not promote efficiency (noting that a key statutory objective of the EA is to promote efficiency) because it restrict EDB’s from charging a price that includes a share of the common costs. This limits the EDB’s ability to charge cost reflective prices, which is topical in the context of the EA’s work on distribution pricing principles.


·      DG operators may be narrowly incentivised by the ACOT payments to reduce transmission charges during peak periods rather than being encouraged to improve wider efficiencies such as avoiding or deferring security of supply investment.


Next steps


The EA will receive submissions on this issue until 5pm on the 26th July 2016. For help with compiling a submission, pick here or call Phil on (07) 854-6541.


System operations and security


Aus – what’s happened in Tasmania ??




Tasmania has a lot of hydro-electric generation, which probably fits well with most peoples’ view of Tasmania as being green and leafy with reasonable rainfalls. This article examines the impact of recent low rainfalls and considers the wisdom of increasing dependence on renewable generation.


Overview of Tasmania’s electricity system


Key features of Tasmania’s electricity system are…


·      The system is predominantly winter loaded, with a maximum demand of about 1,900MW.


·      The system has an installed capacity of about 2,925MW. This is broken down as follows…


·      About 310MW is wind


·      About 2,270MW is hydro


·      About 345MW is thermal


·      The system can also import up to 480MW (or export up to 500MW) via the Basslink undersea cable, giving Tasmania an effective installed capacity of about 3,400MW.


·      Annual energy consumption is about 10,800GWh.


·      Long-run average annual generation is about 8,700GWh, however it is noted that the size and nature of many of the hydro catchments introduces significant year-on-year variability in generation.


·      Water storage averaged around 35% to 40% over the 2000 to 2010 period, with a low of 19% in 2008.


The last two facts and figures in particular indicate that Tasmania is quite dependent on annual refilling of all its hydro lakes.


Recent events


Several significant events have recently occurred in Tasmania…


·      The main combined cycle plant at Tamar Valley was decommissioned in August 2015, following a convergence of low demand, high hydro inflows and high imports from the Basslink cable.


·      In December 2015 the Basslink cable experienced a fault. This may take until May 2016 to return to service.


·      Inflows into the major catchments are at record lows, with storage also falling to record lows (less than 13% and falling as of late April 2016, but with some significant recovery in May due to heavy rain).


Responses to low hydro inflows


The immediate response has been to re-commission the combined cycle plant at Tamar Valley and hire about 200MW of diesel generators.


Going back in time, readers might be intrigued to note that a prolonged drought in 1967 and 1968 resulted in the 2 x 120MW oil-fired Bell Bay station being built on the Tamar River. The sole reason for building Bell Bay was to provide dry year reserve, and not surprisingly it only generated about every 5 or 6 years (readers might recall similar thinking behind Marsden A in New Zealand). Development at Bell Bay included…


·      Commissioning of the 2 oil-fired steam turbines in 1971 and 1974 respectively.


·      Conversion of those 2 oil-fired units to gas in 2003 and 2004 respectively.


·      Installation of 120MW of gas turbines in 2006 (now part of Tamar Valley).


·      Installation of a further 58MW gas turbine in 2009.


·      Installation of a 210MW combined cycle plant in 2009.


·      Decommissioning of the 2 original steam turbine units in 2009.


·      Decommissioning of the combined cycle plant in 2015.


This indicates that Tasmania built up a portfolio of about 620MW of thermal generation, only to reduce it back to about 170MW by 2015.


Thinking about dry year security


Construction of oil-fired steam turbines seemed to be the preferred way of de-risking hydro-based systems with low levels of storage, and that has arguably stood the test of time. There is no doubt that modern political pressures to reduce CO2 emissions have changed the way electricity planners think about thermal plant, but as the companion article in this issue reveals that doesn’t mean a withdrawal of all thermal plant.


NZ – keeping Huntly going for a few more years




Pipes & Wires (refer to PW #148) has previously examined the closure of various thermal stations, particularly the possibility that the two remaining 250MW gas-fired and coal-fired units at Huntly might close in late 2018. This article examines the recent decision to retain those two units until the end of 2022.


Previous plant closures


Recent plant closures were as follows (with the planned closure of Huntly noted in the last row)…


Effective date


MW withdrawn

Cumulative MW withdrawn

October 2014

Huntly #3.



June 2015

Huntly #4.



September 2015

Otahuhu B.



Late 2015




Late 2018

Huntly #1 and #2.




The introduction of low marginal cost generation into the system has reduced the annual GWh from the thermal stations. This left the respective owners with high fixed costs but no corresponding revenue, prompting the inevitable question of whether to decommission the stations. That in turn has led to considerable anxiety about what would happen in the inevitable dry years and considerable debate about whether Huntly really would close.


The decision


In late April 2016 Huntly’s owner, Genesis Energy, entered into a range of bilateral contracts with the other generators that will see Huntly #1 and #2 remain in service until December 2022.


Looking at this decision from various angles


Various angles on this issue include…


·      From a system operation and security angle, the decision is a welcome victory for common sense (refer to the article on Tasmania in this issue, and the articles on the UK in previous issues).


·      From a climate change angle, this will undoubtedly be seen as a disaster.


·      From an economic angle it is probably the least cost option … Huntly #1 and #2’s annual stand-by costs will probably be insignificant in comparison to the economy-wide losses from a dry year.


·      From a political angle which has to try and balance all three issues (the trilemma) it would seem that the risk of a dry year shortage is less desirable than losing popularity with the environmental movement.


What we can be sure of is that this issue is not going to go away.


Nuclear energy


Australia – the Royal Commission reports back




The South Australian Government has been holding a Royal Commission into the nuclear fuel cycle. Pipes & Wires examination of this issue began with #147 and continued into #150. This article examines the Final Report.


Terms of reference of the Royal Commission


The terms of reference of the Royal Commission were to investigate the following 4 aspects of the nuclear fuel cycle as directly applicable to South Australia…


·      Exploration and mining.


·      Processing.


·      Nuclear electricity generation.


·      Storage and disposal of waste.


The Commission’s Final Report


Key findings of the Final Report include…


·      That development of a disposal facility for international used fuel and intermediate level waste could generate a nett surplus of about $100b over a 120 year life. It is noted that social consent would be a major factor in progressing this.


·      Current state and federal mining regulations are sufficient to allow a safe expansion of mining activity, however the approval requirements are duplicative and could be simplified between the state and federal levels.


·      The greatest risks from Uranium ore processing are chemical (rather than radiation) and are well understood and managed. However there is an over-supply of these services at present.


·      That nuclear power generation is sufficiently safe to be considered as part of the State’s energy mix, however it is not commercially viable under the current market arrangements.


Some closing comments


The final Report represents a pretty comprehensive analysis of the nuclear fuel cycle and concludes that the risks of the various segments of the cycle are well understood and manageable, but that the actual use of nuclear fuel (for electricity generation) is commercially unviable.


Regulatory decisions


Aus – gas under pressure in the Northern Territory




Most readers will be familiar with the requirements for covered gas transmission pipelines to have their allowable revenue reset every 5 years. This article examines the access decision process to date for the Amadeus Gas Pipeline in Australia’s Northern Territory for the 5 year regulatory period from 1st July 2016 to 30th June 2021.


A bit about the Amadeus Gas Pipeline


The AGP stretches 1,629km from Darwin to Mereenie, Palm Valley and Alice Springs, and has a capacity of about 100TJ per day. The major connected user of the AGP is the Power & Water Corporation, for the supply of its gas-fired generation.


The legal framework


The AER’s powers and duties, including with respect to regulating the AGP, are set out in the National Gas Law (NGL) and the National Gas Rules (NGR). The NGL requires the AER to perform its functions in a manner likely to contribute to the National Gas Objective “to promote investment in, and efficient operation of, natural gas services for the long term interests of consumers of natural gas with respect to price, quality, safety, reliability and security of supply of natural gas”.


The determination process to date


The following table sets out the decision process to date…



Proposed access arrangement

Draft decision

Revised access arrangement

Final decision

Total revenue requirement










Nominal vanilla WACC





Opening capital base
















Pipes & Wires will comment further once the final decision emerges.


NZ – setting the WACC for electricity and airports




The Commerce Commission recently released its cost of capital decision for the year ending 31st March 2017 for…


·      Electricity distribution businesses.


·      Wellington Airport.


This article examines the key features of that determination.


Regulatory frameworks


The regulatory frameworks are set out in…


·      Clauses 2.4.1 to 2.4.7 of the Electricity Distribution Services Input Methodologies Determination 2012, and


·      Clauses 5.1 to 5.7 of the Commerce Act (Specified Airports Services Input Methodologies) Determination 2010.


Key features of WACC’s


Key features of the gas distribution WACC’s include…



25th percentile


67th percentile

75th percentile

Vanilla WACC





Post-tax WACC






Key features of the Wellington Airport WACC’s include…



25th percentile


75th percentile

Vanilla WACC




67th percentile Vanilla WACC





Aus – the Queensland electricity transmission determination




The electricity transmission grid owner in the Australian state of Queensland, Powerlink, recently submitted its regulatory proposal (rate case) to the Australian Energy Regulator for the five year period from 1st July 2017 to 30th June 2022. This article examines the key features of Powerlink’s proposal and in particular how it expects to treat the impact of emerging technologies.


Regulatory framework


The regulatory framework is based on the National Electricity (South Australia) Act 1996, which provides for the making of the National Electricity Rules (version 79 at the time of writing). Electricity transmission determinations are principally made pursuant to Chapter 6A of the Rules.


A bit about the assets


Powerlink is 100% owned by the Queensland state government. It’s assets include 15,000km of lines and cables at 66kV, 132kV, 275kV and 330kV, and 135 substations over the 1,700km stretch from north of Cairns to the NSW border.


Powerlink’s views on emerging technologies


Powerlink’s proposal clearly notes that emerging technologies are changing both the nature and volume of the demand for transmission services. Key features of Powerlink’s thinking include…


·      A lesser role for the transmission of centrally generated electricity as more customers install rooftop solar.


·      Reduction of the need for grid investment to cover short duration peaks as improving battery technologies flatten the demand profile.


·      Significant shifts in the timing and magnitude of demand peaks due to solar, batteries and electric car recharging.


·      How pricing for rooftop solar can fairly fund existing assets.


The AER’s acknowledgment and treatment of these issues will prove critical in obtaining a determination that correctly incentivises future investment.


The determination process to date


The determination process to date includes the following…




Draft determination

Revised proposal

Final determination











Opening RAB










Regulatory depreciation





Total smoothed revenue






Pipes & Wires will comment further as this determine progresses.


France – gas under pressure




The French energy regulator, the Commission de Regulation de l’Energie (CRE) has been compiling the tariff that will apply to the gas distribution operator GRDF for the control period starting on 1st July 2016, known as ATRD5.


A bit about GRDF


Gaz Réseau Distribution France (GRDF) supplies about 11,000,000 end-use customers with gas distribution services throughout France from its 196,000km of pipelines. GRDF itself is a subsidiary of ENGIE which owns and operates 300,000km of gas pipelines in 10 countries.


Legal framework


The CRE derives its statutory powers from the Code de l’Energie, which was adopted into French law on 13th July 2005. In particular, Article L452 sets out the framework for gas transmission and distribution tariffs. 


The proposed ATRD5 tariff


Major features of the ATRD5 tariff are…


·      A proposed 2.8% tariff increase compared with the 11.7% sought by GRDF.


·      An escalation of 0.8% per year.


·      Some ambitious productivity targets.


·      A proposed WACC of about 5%.


Pipes & Wires will comment further on ATRD5 as the CRE releases its final decision.


Aus – the Tasmanian electricity distribution determination




The electricity distributor in the Australian state of Tasmania, TasNetworks, recently submitted its regulatory proposal (rate case) to the Australian Energy Regulator for the two year period from 1st July 2017 to 30th June 2019. Readers may recall that the Tasmanian government amalgamated its transmission grid Transend with its distribution business Aurora Energy on 1st July 2014 (refer to Pipes & Wires #113). This two year regulatory period is to align the regulatory periods for TasNetworks transmission and distribution businesses.


A bit about the assets


TasNetworks distribution network comprises 22,400km of lines and cables, 18 large distribution stations and 33,000 small distribution substations. These assets supply about 284,000 customers.


One of the features of TasNetworks is that because it was originally vertically integrated as the Hydro Electric Commission there were more transmission substations and few distribution substations.


Regulatory framework


The regulatory framework is based on the National Electricity (South Australia) Act 1996, which provides for the making of the National Electricity Rules (version 79 at the time of writing). Electricity transmission determinations are principally made pursuant to Chapter 6 of the Rules.


The determination process to date


The determination process to date includes the following…




Draft determination

Revised proposal

Final determination











Opening RAB










Regulatory depreciation





Total smoothed revenue






Pipes & Wires will comment further as this determine progresses.


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.


House-keeping stuff


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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.