Pipes & Wires


Issue 168 – October 2017


From the editor’s desk…


Welcome to Pipes & Wires #168. A lot seems to have happened in the United States at both State and Federal levels over the last month or so with tariff restructuring and paying for grid support and reliability, so this issue does have a dominant focus on the USA.


This issue also examines three network access decisions … two electricity transmission decisions in Australia and a gas distribution decision in Ireland. So … until next month, happy reading…


Recent client projects


Recent client projects include…


·      Reviewing recent AER decisions to understand the expectations around asset management practices and methods.


·      Reviewing the AER’s recent treatment of network transformation expenditure.


·      Compiling overhead conductor and wooden cross-arm fleet strategies.


·      Identifying the issues around customer-owned lines on private land.


·      Developing a risk-based tree trimming strategy.


·      Developing an EV charging strategy.


·      Analysing transmission charges as a percentage of total electric bills.


·      Compiling a strategy for improving the resilience of a sub-transmission network.


·      Developing a best-practice guideline for smart metering.



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Electricity markets & grid security


US – changing the business model




Increasing penetration of embedded generation has the potential to disrupt the traditional regulated kWh-based business model. This article examines recent regulatory changes in the US state of Illinois that could both encourage uptake of embedded generation and minimise disruption.


The regulatory framework


The regulatory framework is based on the Future Energy Jobs Act which began life as Senate Bill 2814 which amends inter alia the Public Utilities Act. Key features of the Act include…


·      Allocating $140m per year for the purchase of renewable energy credits to support new wind and solar projects.


·      Allowing electric companies to treat rebates paid to solar owners as virtual regulatory assets that are tariff-based and earn a guaranteed return. This will lessen the impact of stranding traditional network investments.


·      Amends the Renewable Energy Portfolio Standard to ensure stable and predictable funding for wind and solar projects.


The new business models going forward


The underlying premise of the new business model is that electric companies will become distribution system platform providers which neutrally manage multi-directional power flows and oversee ultimately reliability (a bit like what transmission grids have become).


The important asset strategy issue is that an open-access network is likely to have the same capital costs and probably higher operational costs than a conventional uni-directional network, so one way or another whatever the revenue model ends up as, it will need to provide at least as much cash as the current kWh-based model. It appears that the provisions of the Future Energy Jobs Act will provide for those new business models.


Embracing the “utility of the future”


Utility Consultants in conjunction with the UMS Group have advised several electric companies on “the utility of the future”. For more information pick here to contact Jeff Cummings from the UMS Group.


US – correctly paying for third-party demand response




Instantaneous matching of generation to demand has partially migrated from supply-side to demand-side.  Emerging technologies hold the promise of further migration, but with the added twist of third-party provision. This article examines the difficulty of correctly paying for third-party demand response (DR) using recent events in California as a starting point.


A bit about demand response


Historically, instantaneous matching of generation to demand has included…


·      Spinning reserve, in which specific hydro generators are synchronised to the grid but operate at no load (so they can quickly pick load if another generator trips).


·      Load-shedding, in which load control relays are used to disconnect load when the grid frequency drops to specified levels.


The improved response time (from minutes for the old motor-generator injection plant to milli-seconds for electronic injection and smart meters) and the willingness of customers to be interrupted for short periods has obviously made demand side more attractive than supply side which requires an expensive hydro plant to not generate. There are 3 useful angles to examine demand response from…


·      The simple technology issue (outlined above).


·      The entry of third-party demand response provides into an arrangement that was historically provided by only the electric company or its customers.


·      The basis of quantifying and paying for third-party DR.


Ensuring that third-party DR is correctly paid


During California’s recent heatwave, two energy storage providers successfully offered aggregations of automated load shedding into the wholesale market (which is in accordance with the Cal ISO’s rules).


A key issue to emerge is that the valuation of and hence payment for demand response (DR) depends heavily on how much load was reduced (referred to as the counterfactual, and like most arguments involving a counterfactual, we don’t know for sure what that counterfactual really was).


However the Cal ISO’s approach dates from 2010 when there wasn’t much DR on the grid. Its’ current approach to quantifying DR is to compare the post-DR load to what the load was in the previous 10 days which could understandably under-quantify the DR if the previous 10 days had been cooler. One of the DR providers’ claims that using this approach has led to only being paid for 53% of the DR it provided.


Improving the DR payment approach


The Cal ISO recognised that the maturing state of DR (in part driven by new technologies that allow third-party participation) requires a new settlement method. Improvements are being developed by the big electric companies, so Pipes & Wires will comment further as news emerges.


The editor comments


The transition from a traditional uni-directional, regulated network business model to an open-access, multi-directional model in which the electric company provides coordination and reliability will require thoughtfully developed measurement and payment methods to provide certainty of investment for third-party participants and certainty of cost recovery for the electric companies.


US – who pays for grid reliability services ?




The recently released DOE report on markets and reliability (refer to Pipes & Wires #167) concluded inter alia that market mechanisms need to be developed for paying generators that provide grid reliability, resilience and buffering. This article looks at the FERC’s response to that recommendation.


Issues raised in the recent DOE report


The DOE report notes that “market mechanisms are designed to incentivise individual resources rather than develop balanced portfolios. System operators are working towards recognising, defining and compensating for reliability and resilience-enhancing resource attributes … but more work must be done” ie. there needs to be improved market mechanisms for paying generators that provide frequency keeping, controllable generation, peak capacity etc. Readers might’ve recalled that getting properly paid for the electricity services provided by controllable generation was one of the building blocks of the Nuclear Promise (refer to Pipes & Wires #157).


The FERC’s views


Initial comments from FERC Chairman Neil Chatterjee include the views that…


·      Coal-fired generators should be properly compensated to recognise the value they provide to the system.


·      That provision of grid reliability might be better implemented by making grid reliability features a requirement for connection rather than through a market mechanism.


The most obvious implication of the second point above is that wind and solar will need to contribute to grid stability if they want to grid connect. Pipes & Wires will comment further as the FERC’s thinking evolves.


US – recovering the costs of baseload generation




Recovering the full costs of (traditionally understood) coal and nuclear baseload generation as they are displaced from the market by wind, solar and cheap gas has been a thorny issue in many jurisdictions. This article examines the Department of Energy’s (DOE) recent proposal for better recovery of baseload generation costs, and follows on from the previous article on paying for grid reliability.


The DOE’s proposal and its context


The DOE has recently filed a Notice of Proposed Rulemaking (NOPR) directing the Federal Energy Regulatory Commission (FERC) to “accurately price generation resources necessary to maintain reliability and resiliency”. The context to the NOPR is the recent DOE study on markets and reliability ordered by Secretary of Energy Rick Perry (refer to Pipes & Wires #163 and #167).


The regulatory framework


The regulatory framework includes…


·      s403 of the Department of Energy Organisation Act, which provides for the DOE to propose inter alia rules with respect to any function under the FERC’s jurisdiction.


·      ss205 and 206 of the Federal Power Act, which broadly provides for the FERC to establish just and reasonable rates (tariffs).


Key requirements for generators to be eligible


Key requirements for a generator to be eligible for full cost recovery under the NOPR are to…


·      Have 90 days of fuel on-site.


·      Be able to provide ancillary services as well as reliability services.


·      Comply with environmental regulations.


·      Not already be subject to a cost-of-service recovery by a State.


The wider context of cost recovery


Pipes & Wires #157 noted that the 2nd of the 4 building blocks set out in the Nuclear Promise’s strategic plan is “leverage federal and state policies to ensure monetary recognition of nuclear energy’s value”, for which one of the specific actions is to reform capacity markets by developing market mechanisms that value the attributes of nuclear power plants. So it looks like the nuclear industry might get its wish on this one (and whether it ends up as a market or regulated solution remains to be seen).




The NOPR seems to have lit a fire in Washington, with FERC pushing back in defence of existing market structures.


Tariffs & pricing


US – regulatory support for embedded generation tariffs




Suppliers and lobby groups alike have vigorously opposed any requirements for rooftop solar customers to pay higher prices. This article examines a recent regulatory decision in the US state of Kansas that may allow electric companies to establish separate prices or tariff classes for customers with embedded generation to limit the need for subsidies from other customers.


Background to the KCC’s decision


In July 2016 the Kansas Corporation Commission (KCC) opened a General Investigation to examine various issues around prices and tariff structures for embedded generation which was expected to include an assessment of the quantifiable costs and benefits of embedded generation. All the electric companies under the KCC’s jurisdiction were named as parties to the General Investigation, allowing them the opportunity to submit evidence.


The legal standard


Key features of the legal standards are inter alia as follows…


·      Every public utility in Kansas is required to … establish just and reasonable rates (prices).


·      Just and reasonable rates are those that fall within a zone of “reasonableness” which balances the interests of present and future ratepayers (customers), and the public interest.


·      The Kansas Supreme Court has recognised that the touchstone of public utility law is that rule that one class of consumers shall not be burdened with costs created by another class.


The KCC’s decision


In September 2017 the KCC concluded inter alia that…


·      Electric companies may establish a separate rate (tariff) class and propose new rate design (pricing methodologies) for embedded generation customers to ensure that those customers share in the fixed costs of the electric grid and are not subsidised by other ratepayers (customers).


·      Customers who install embedded generation prior to new tariffs taking effect will be allowed to remain on the existing tariff until 2030.


Responses from the various sides to the issue


Responses to the KCC’s decision are understandably mixed…


·      Electric companies seem happy that they can minimise subsidies and equitably recover costs.


·      Customer advocates and solar lobby groups are disappointed with the KCC’s decision. This tends to reinforce the sad conclusion that solar owners somehow expect to free-ride the network.


US – rebalancing the fixed and variable tariffs




Opposition to increasing the fixed component of electric tariffs is nothing new … promoters of rooftop solar have claimed that increasing the fixed tariff component (whilst also reducing the variable component) undermines the benefits of solar. This article examines recent plans to rebalance tariffs in the US state of Nevada in response to the new nett metering law.




Electric distribution companies have a high ratio of fixed to variable costs, but historically have recovered most of those fixed costs through variable (kWh) tariffs. That was all fine as long as customers kept on consuming similar annual kWh’s, but the advent of rooftop solar has eroded those kWh volumes and with it the recovery of fixed costs that over time will under-fund the distribution business.


The most obvious alternative is to re-balance the mix of fixed and variable tariffs to make the revenue less dependent on kWh consumption. This has two economic consequences…


·      In the short term it makes rooftop solar less beneficial by reducing the avoided costs of imported kWh and increasing the unavoidable monthly fixed charge (and as far as I know, electric companies have never denied this).


·      In the long term it increases the incentive to go off-grid and avoid the fixed monthly tariff (the death spiral).


Nevada’s nett metering law


Assembly Bill 405 was introduced to the Nevada Legislature in March 2017 with the aim of…


·      Protecting customers who use renewable energy.


·      Revising provisions for nett metering.


A key feature of the Bill was that it restored nett metering rates to 95% of the retail rate. The Bill was signed into law in June 2017 by Governor Brian Sandoval.


NV Energy’s proposed tariff rebalancing


Key features of NV Energy’s proposed tariff rebalancing include…


·      Increasing the fixed monthly tariff from $12.75 to $16.76, but noting that customer bills should remain about the same because of a corresponding reduction in the kWh tariff.


·      Paying rooftop solar customers 95% of the prevailing import rate for their exported energy. This will decline by 7% for every 80MW of rooftop solar installed until a floor of 75% is reached.


The Nevada PUC’s response


The PUC’s response was awaited at the time of publication, so Pipes & Wires will pick up this story again in the future.


Network access decisions


Aus – the TransGrid revenue determination




The Australian Energy Regulator (AER) recently published its Draft Decision for TransGrid for the five year period beginning on 1st July 2018. This article examines the key features of that Draft Decision.


A bit about TransGrid


TransGrid owns and operates 13,000km of lines at 500kV, 330kV, 220kV and 132kV that supply 99 bulk supply substations (GXP’s). Following the completion of the 99 year lease process in 2015, TransGrid is owned by a consortium led by Hastings Funds Management.


Regulatory framework


The basis of the regulatory framework is Chapter 6a of the National Electricity Rules, which is made pursuant to the National Electricity Law.


Key features of the process


Key features of the process to date include…



Initial Proposal

Draft Decision

Revised Proposal

Final Decision











Opening RAB










Regulatory depreciation





Smoothed revenue






Next steps


The next step is for TransGrid to submit its Revised Proposal, after which Pipes & Wires will comment further.


Ireland – setting the gas distribution revenue




After examining a whole bunch of Australian gas pipeline tariffs in PW #167, we now move half a world away to take a quick look at a recent gas distribution revenue decision in Ireland. This article examines the PC4 gas distribution revenue decision which applies to Gas Networks Ireland’s distribution business for the 5 year period starting on 1st October 2017.


A bit about Gas Networks Ireland


Gas Networks Ireland owns 2,200km of transmission pipelines and 11,200km of distribution pipelines throughout Northern Ireland and the Republic of Ireland that supply 674,000 end-use customers. Bulk supply is taken from 3 undersea pipelines from Scotland.


GNI is the residual business after the sale of the Bord Gáis Éireann supply business to Centrica in 2014, and is part of the statutory corporation Ervia.


The regulatory framework


A key feature of the regulatory framework is Section 10 of the Gas Act 1976, which limits the revenue to all charges properly chargeable to revenue and a reasonable return on the capital it employs.


Key features of the PC4 decision


Key features of the PC4 decision include…



Sought by GNI

CER decision














Aus – the Murraylink revenue determination




The Australian Energy Regulator (AER) recently published its Draft Decision for the Murraylink for the five year period beginning on 1st July 2018. This article examines the key features of the Draft Decision.


A bit about the Murraylink


The Murraylink is a 180km long HVDC cable link between Berri (South Australia) and Red Cliffs (Victoria) which operates at 150kV and has a rating of 220MW. It was built by TransEnergie Australia and commissioned in 2002, and is now owned by Energy Infrastructure Investments Pty Ltd.


Regulatory framework


The basis of the regulatory framework is Chapter 6a of the National Electricity Rules, which is made pursuant to the National Electricity Law.


Key features of the process


Key features of the process to date include…



Initial Proposal

Draft Decision

Revised Proposal

Final Decision











Opening RAB





Nominal vanilla WACC





Regulatory depreciation





Smoothed revenue






Next steps


The next step is for Murraylink to submit its Revised Proposal, after which Pipes & Wires will comment further.


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 classic historical photo’s with humorous captions looks at some of the salient features of price control. Pick here to download.


Wanted – old electricity history books


Now that I seem to have scrounged pretty much every book on the history of electricity in New Zealand, I’m keen to obtain historical book, journals and pamphlets from other countries. So if anyone has any unwanted documents, please email me.


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.


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