Pipes & Wires


Issue 157 – October 2016


From the editor’s desk…


Welcome to Pipes & Wires #157. This issue begins with a wider look at solar and feed-in tariffs, and then notes a decision in the US to reject the inclusion of car chargers in a regulated asset base. We then take a quick look at the closure of a lignite-fired power station in Australia in the context of system security. We then present 3 articles that take us through the entire lifecycle of nuclear generation. This issue then concludes with some thoughts on whether Australia’s electricity markets are working.


Please also note a correction to the article on reducing the asset beta for gas pipelines in PW #156. The wording “how much less than 1” in the 3rd paragraph implied that the market taken in aggregate has an asset beta of 1 when it is about 0.7. Comparison of the current asset beta of 0.44 and the proposed asset beta of 0.34 with 1 instead of 0.7 could imply that regulated pipes & wires businesses are believed to have less risk than is actually the case.


So … until next month, happy reading…


Emerging themes & trends


Some of the industry themes and trends that are emerging include…


·      What appears to be some confusion amongst regulators about to how to regulate emerging technologies such as batteries and solar. Given that these technologies seem to be giving customers increased choice about where they obtain their electricity from, perhaps the question should be whether to regulate.


·      Concern over foreign ownership of critical infrastructure. This issue seems to have escalated from one of energy security to one of national security.


·      Diverging views of the green lobby on nuclear energy. Some environmental groups remain steadfastly opposed to nuclear energy, whilst other groups are now supporting nuclear as a useful transition from coal to renewables.


·      An increasing recognition that improved asset condition information is the next frontier for improved asset management decisions, and from there to strengthened regulatory proposals (rates cases).


·      A rapidly increasing awareness of the importance of thermal generation for renewable buffering, both in the context of moment-by-moment fluctuations in wind and solar, but also in the traditionally understood sense of dry hydro years.


·      A sense that some governments may be losing patience with the slow pace of the transition to renewables, and the heightened possibility that those governments may move from encouraging through incentives to mandating through sanctions.


Solar, wind, batteries & micro grids


US – how much is solar really worth to a distribution network ?




Some promoters of roof-top solar claim that the benefits are substantial. This article takes an analytical look at what the real value of roof-top solar might be and examines a recent regulatory investigation of that value in the US state of Arizona.


What are the bases for valuing roof-top solar ?


Some of the bases for valuing roof-top solar include…


·      Reducing peak demand at the point of transmission grid connection. That is important if the distribution company pays a demand charge to the transmission company.


·      Avoiding peak generation. This is only really important if that peak generation is expensive (eg. oil-fired) … if it is hydro plant like the Snowy Hydro in Australia, then the avoided cost could actually be quite low.


·      Avoiding distribution growth CapEx. If that specific part of the distribution network is unconstrained (ie. has plenty of capacity headroom), then the avoided cost is pretty much nil.


·       The value of the energy exported into the grid. This should be no greater than the prevailing cost of a kWh from any of the retailers trading on that network.


This strongly suggests that solar energy exported into the network during the middle of the day is actually not worth that much. Separate from and additional to this issue is the reduced nett kWh imported by roof top solar customers that leads to a reduced revenue contribution to the electric company (known as “solar cost shifting”).


The Arizona Corporation Commission’s recent work


Over the last few years, electric companies in the American south-west have steadily attempted to rebalance their mix of fixed and variable tariffs (refer to Pipes & Wires #149, #151 and #154) to mitigate solar cost shifting. This has understandably met with huge resistance from the roof-top solar industry and left regulators struggling to find an analytically sound position.


In October 2015 the Arizona Corporation Commission (ACC) ordered that an evidentiary hearing be held to better inform inter alia the solar cost shifting debate. Following 3 days of hearings during August 2016, the ACC chose to delay any specific decisions on solar remuneration rates. Mindful of the Nevada decision (refer to Pipes & Wires #149), the ACC stated its determination to find a good policy compromise.


Key features of the evidentiary hearing


The evidentiary hearing is occurring within the previously established docket E-00000J-14-0023 entitled “In the matter of the Commission’s investigation of value and cost of distributed generation”. The scope of the hearing included presentation of studies and proposed methodologies on the cost of connecting distributed generation, and the value associated with distributed generation.


Next steps


The next steps include the ACC reaching its conclusions, and then publishing those conclusions. Pipes & Wires will comment further as those conclusions are published.


Aus – abolishing the regulated retail feed-in tariff in South Australia




Regulated retail feed-in tariffs are coming to an end in many jurisdictions, in part because governments are becoming uneasy about the subsidies they provide. This article examines the abolition of the regulated retail feed-in tariff in South Australia.


Re-capping exactly what feed-in tariffs are


A feed-in tariff is the price paid to an embedded generator for the electricity that they feed back into the distribution network. FIT’s have historically been greater than the tariff at which the same electricity would be purchased from an electricity retailer, essentially subsidising the cost of roof-top solar.


Feed-in tariffs come in two types…


·      Retail feed-in tariffs (R-FIT), which is the amount paid to the embedded generator by an electricity retailer as payment for the electricity (kWh).


·      Distribution feed-in tariffs (D-FIT), which is the amount paid by the electricity distributor.


Recent moves in South Australia


The South Australian Government deregulated small customer standing contract retail pricing in February 2013.  For the previous decade, the Essential Services Commission Of South Australia (ESCOSA) had set retail standing contract prices for residential and small business whilst retail competition also provided choice and potentially lower prices. Whilst ESCOSA then ceased setting default standing contract prices, they continued to set regulated retail feed-in tariffs pending the development of adequate competition in that sector.


ESCOSA recently abolished the minimum R-FIT, which was 6.8c/kWh. ESCOSA holds the view that there is sufficient competition amongst retailers to buy electricity from embedded generators (mainly roof-top solar) for suitable market prices to be established.


For the avoidance of doubt, the D-FIT will continue to be paid by SA Power Networks until 30th June 2028 to all solar customers that installed before 1st October 2011. This is a state government legislated scheme with a premium payment of 44c/kWh.  A subsequent scheme for solar installations before 1 October 2012 will cease being paid a premium payment of 16 cents/kWh from 1 October 2016.


What this means for the various electricity sector participants


So what could abolishing the R-FIT mean for the various electricity sector participants ? Here’s some observations…


·      Retailers will have the opportunity to offer R-FIT’s lower than the regulated R-FIT if that is what they determine the true value of exported electricity to be. They may also have to offer higher R-FIT’s to capture new solar customers.


·      Roof-top solar customers may have to shop around for the retailer offering the best deal.


·      Non-solar customers may also shop around for the retailer offering the best deal. As retailers adjust their R-FIT’s, the subsidy required from non-solar customers to fund the R-FIT will presumably also adjust. Hence a retailer that offers a high R-FIT to attract solar customers may also require a high subsidy to fund that R-FIT and therefore lose non-solar customers who can obtain a lower price from other retailers.


·      The cost of grid-scale solar in front of the meter will presumably set an upper limit to the R-FIT (a simple “make or buy” decision by the retailer).


·      All distribution customers will continue to contribute to the D-FIT.


So it appears that this will create a delicate balancing act for retailers, and it will be interesting to see how the various retail offerings play out. It will also be interesting to see what retail and solar/battery offers develop over time for the substantial amount of PV export from those customers not being paid a D-FIT premium, particularly with batteries receiving significant media promotion. 


Pipes & Wires will re-examine this in a year or so to see what has happened.


US – making the best use of roof-top solar




One of the problems with roof-top solar is that it generates most of its electricity during the hot, sunny periods of the day when domestic electricity consumption tends to be lower. This lengthy article examines two interconnected issues…


·      The changing shape of the traditional demand profile.


·      The Hawaii Public Utilities Commission (HPUC) recent approval of a 2 year pilot program that will give up to 5,000 of Hawaii Electric Company’s (HECO) customers the option of choosing time-of-use (TOU) tariffs designed to encourage consumption during the hot, sunny periods and discourage peak period consumption that requires oil-fired generation.


The demand profile issue


We’re all familiar with the typical domestic demand profile that climbs steadily from early morning as people get up, then declines during the daytime period and then climbs into the early evening period when people get home from work and cook dinner, and then finally declines during the late evening as people go to bed. Historically the peaks were greater in winter.


I say typical because changes in technology have allowed the typical demand profile to change. A couple of examples include…


·      Starting back in the 1940’s when domestic air conditioning became cheaper and summer afternoon and early evening peaks began to increase. Now that air conditioners are dirt cheap this is now at the point where many networks are peaking during summer (which has obvious consequences for component de-rating).


·      Development of demand management programs such ripple control of hot water cylinders. This shifted the hot water load to the night-time and mid-day troughs on the demand profile, using the thermal inertia of the water in the cylinder.


·      Development of off-peak storage heating. Again, this used the thermal inertia of bricks and concrete in the heater cabinet or the floor slab to shift space heating demand to the night-time troughs.


·      The development of two-rate meters in the late 1980’s. This encouraged loads such as pottery kilns and clothes dryers to be used at night, shifting demand into the night-time troughs.


·      The introduction of electric cars. Off-peak charging would obviously fill the troughs (which Orion’s predecessor the Christchurch Municipal Electricity Department promoted in 1917) and perhaps more importantly shift some very substantial demand away from peak periods.


Each of these overlays embodies a range of customer behavior, which will in part be influenced by prices and perhaps more specifically by the customers’ ability to see those prices in real time and their willingness to change their consumption patterns. It’s probably fair to say that over the last 15 years or so cheap air conditioners have probably eroded the improved network utilisation that came from over 40 years of careful demand management, and we now have the opportunity to correctly encourage electric car recharging into off-peak periods.


Feeder over-loading


Some of HECO’s distribution feeders are now becoming overloaded. Not overloaded from demand in the traditional sense of “load”, but overloaded in the emerging sense of embedded generation (but of course the feeders don’t make that distinction … current is current, regardless of its direction). Mitigating this overloading could be done in 1 or more of the following ways…


·      Install bigger conductors, which obviously has a capital cost that needs to be recovered through regulated tariffs.


·      Reduce the injected generation during periods of low “internal demand” to reduce the amount of “exported” electricity that is overloading feeders. This would be contrary to the whole philosophy of renewable energy, and also foregoes free energy.


·      Shift “internal demand” from traditional periods into the hot, sunny periods so that most of the roof-top solar electricity is used in the house rather than exported into the network.


·      Re-orient everyone’s solar panels to the north-west so they generate when the evening peak is starting to climb.


HECO’s tariffs


The basis of HECO’s TOU tariffs appears to be shifting “internal demand” from traditional usage periods into the hot, sunny periods of the day. The following tariffs have been proposed…




Big Island

Mid-day 9am to 5pm



On-peak 5pm to 10pm



Off-peak 10pm to 9am




The key differences from the existing tariffs are…


·      The mid-day tariff is lower than the current tariff, encouraging consumption.


·      The on-peak tariff is higher than the current tariff, discouraging consumption.


This should encourage use of appliances such clothes dryers and dishwashers during the day, and may also encourage up-take of ice-bank cooling (the opposite of night-store heating). Of course this comes at the cost of installing TOU metering, for which HECO has already filed a rate case that included $340m for smart metering.


This does show great promise, so Pipes & Wires will re-visit this issue in a year or so.


Regulatory decisions


US – recovering the cost of electric car recharging stations




It would seem that electric car recharging stations are an integral part of energy policy. This article examines a recent case in which the Kansas State Corporation Commission (KSCC) denied a proposal by Kansas City Power & Light (KCPL) to recover part of the Clean Charge Network cost from customers, and also considers this in the context of a wider disconnect between desirable policy outcomes on the one hand and paying for those outcomes on the other hand.


KCPL’s proposal


KCPL’s Clean Charge Network (CCN) originally planned to install more than 1,000 recharging stations throughout the great Kansas City are. It was originally planned that $5.6m of the CCN’s capital cost of $16.6m along with about $250,000 in annual operating costs would be recovered through KCPL’s regulated tariffs by including that cost in the rate base.


The regulator’s response


The KSCC denied KCPL’s proposal for the following reasons…


·      KCPL has failed to demonstrate a legitimate demand for the CCN.


·      While stimulating electric car ownership may be a worthwhile objective, it does not fall within the scope of KCPL providing sufficient and efficient service.


·      Thoughtful location of recharging stations may encourage electric car drivers to visit specific retail areas, so why should the cost of the rechargers fall on KCPL’s customers.


·      The view that between 70% and 80% of recharging occurs at home, and that the number of recharging stations proposed by the CCN is unnecessary.


·      The number of electric cars expected to be within KCPL’s network area by 2020 is expected to be much lower than the 12,000 estimated by KCPL.


·      The CCN is essentially a load-building program that should be funded by shareholders, and not through regulated tariffs.


All in all, a very vigorous denial from the KSCC.


The editor comments


One context to frame this issue within is one branch of government encouraging investor-owned electric companies to contribute to public policy objectives whilst another branch of government won’t allow the cost of that contribution to be recovered. Readers might remember a similar occurrence with Baltimore Gas & Electric’s (BG&E) smart metering proposal a few years ago … a great contribution to energy policy, but all of a sudden not so great when it came to recovering the costs through regulated tariffs.


NZ – determining the WACC for electricity distribution




The Commerce Commission recently released its cost of capital decision that will apply to customised price-quality (CPP) proposals made by electricity distribution businesses from the 30th September 2016. This article examines the key features of that determination.


Regulatory framework


The regulatory framework for setting the WACC is set out in clauses 5.3.22 to 5.3.29 of the Electricity Distribution Services Input Methodologies Determination 2012. This determination is made pursuant to Part 4 of the Commerce Act 1986.


Key features of the WACC’s


Key features of the Vanilla WACC’s include…


CPP period


67th percentile

3 years



4 years



5 years




System operations & security


Aus – closing thermal generation in Victoria




Closing thermal generation ostensibly to reduce CO2 emissions seems to be an emerging trend. This article examines the expected closure of the Hazelwood power station in the Australian state of Victoria.


A bit about Hazelwood


Hazelwood is an 8 x 200 MW lignite-fired steam turbine station located in the Latrobe Valley, about 150km east of Melbourne. The station was built between 1964 and 1971, and over time has supplied up 25% of Victoria’s base load.


Hazelwood was originally owned by the State Electricity Commission of Victoria (SECV). In 1996 Hazelwood was sold to a consortium led by International Power (92%) for $2.35b after which a further $885m was invested in new boilers and turbines. Hazelwood is currently 72% owned by Engie and 28% owned by Mitsui.


The expected closure


At the time of writing this article, Engie is expected to decide whether to close Hazelwood as part of its October board meeting.  There is some media comment, however, that Engie has already advised the Victorian government that it is likely to close Hazelwood as soon as 1st April 2017.


The various viewpoints


Understandably there are a wide range of viewpoints on the expected closure of Hazelwood…


·      The closure couldn’t come soon enough for the environmental lobby. A little research reveals that Hazelwood was the target of environmentalists over localised air quality before CO2 became an issue.


·      The 500 employees and 300 contractors will presumably be unhappy about the expected closure, but in all fairness Hazelwood’s closure has been signaled for about 20 years.


·      The state government seems nervous about job losses in an already depressed area, and has been working on transition plan for displaced workers.


·      WorkSafe Victoria believes the station needed further investment to remain safe. The owners appear unwilling to make that investment, effectively forcing its closure.


The likely impact on system security


Views on the likely impact on system security vary, and in particular the view that coal-fired stations are unnecessary seems to assume that renewables will adequately supply the base load. However the last few years have provided some stark lessons that renewables might be okay as long as we get the right amounts of sun, wind and rain in the right places at the right times but when the wind stops blowing, the clouds gather and the rain and snow don’t fall where the dams have been built the risk of blackouts increases (refer to the article in Pipes & Wires #152 about Tasmania’s recent hydro shortage).


The Australian Energy Market Operator’s (AEMO) National Electricity Forecasting Report notes that although overall electricity consumption is expected to increase by about 11% over the next 20 years, consumption of grid-supplied electricity will increase by only about 0.7% as roof-top solar penetration increases. Perhaps we need to ask the hard “what if” question … what if parts of Australia have prolonged cloud cover and grey, gloomy days (a solar equivalent to Tasmania’s recent low hydro inflows) on which solar panels have significantly reduced output ? What type of generation will fill the gap in the supply curve ?


So what is the right answer ?


So what is the right answer ? Should Hazelwood remain open to provide renewable buffering ? Given its age (almost 50 years), plant type (steam turbine) fuel type (lignite), low efficiency, likely capital investment requirements and likely standing costs Hazelwood is almost certainly not the best pick of the estimated 7,000 MW of surplus generation in the National Electricity Market (NEM) to remain open but the issue remains that some thermal generation will eventually be needed to step into the supply curve during undesirable weather conditions.




US – delivering on the Nuclear Promise




In late 2015 the Nuclear Energy Institute launched a 3 year program focused on improving efficiency and safety, and driving down costs. This article examines the Nuclear Promise, and looks at the wider context of downward cost pressure across the entire generation sector.


Key features of the nuclear promise


The Nuclear Promise has 3 strategic focus areas…


·      Maintain operational focus (mainly focused around safety as a top priority).


·      Increase value (including electricity market reform).


·      Improve efficiency (including a cost reduction target of 30%).


The wider context of downward cost pressure


The nuclear industry faces the following issues, which are putting downward pressure on costs…


·      An abundant supply of natural gas at historically low prices, allowing gas-fired generation to under-cut nuclear.


·      Low growth in national (MWh) demand.


·      Subsidies for renewable electricity that allow wind and solar to under-cut nuclear.


Against these, total nuclear generation costs per MWh have increased by 28% over the last decade.


Improving the value proposition of nuclear generation


The Nuclear Promise’s Strategic Plan sets out 4 building blocks, of which #2 is of particular interest … “leverage federal and state policies to ensure monetary recognition of nuclear energy’s value”. One of the specific actions is to reform capacity markets by developing market mechanisms that value the attributes of nuclear power plants.


The editor comments


Energy markets that only pay for generated MWh seem to have created a race to the bottom in which generation with very low short-run marginal costs (SRMC) capture the $$$ and squeeze higher cost generation further up the supply curve, even though that higher cost generation provides secure capacity. So there is a definite need for additional market mechanisms to reward electricity products such as peak MW and security.


UK – Hinkley Point C gathers speed amidst tightened scrutiny




Pipes & Wires #156 noted that the UK government planned a review of the proposed Hinkley Point C nuclear station soon after Electricité de France (EDF) approved it. This article examines the findings of that review, and also notes the issue of foreign ownership of critical infrastructure.


Key outcomes of the review


The focus of the review was mainly national security, and did not appear to address any commercial (the controversial strike price of Ł92.50 per MWh) or technical (the engineering difficulties encountered at Flamanville #3) issues. The key outcome of the review was a revised agreement in principle with EDF that primarily restricts EDF from on-selling its stake in Hinkley Point C without the UK government’s approval.


It would appear that this new requirement is aimed at China General Nuclear’s 33.5% stake in Hinkley Point C that the UK government now appears nervous about. For their part, UK opposition parties are claiming that the government already has the legal power to prohibit on-sale of a stake, so in fact the new safeguards are not really new at all.


The new legal safeguards


The key safeguards include…


·      The UK government’s ability to prevent the sale of EDF’s controlling stake in Hinkley Point C prior to completion of construction.


·      The UK government will take a special share in all future nuclear power stations that it can use to prevent changes in ownership or part-ownership.


·      The Office of Nuclear Regulation (ONR) will be able to require any nuclear site developers or operators to notify it of any changes in ownership or part-ownership. This will effectively extend the role of the ONR from that of a technical and safety regulator to include national security aspects.


·      Reforms to the government’s approach to ownership and control of critical infrastructure to ensure that the national security implications of foreign ownership are fully understood.


The thorny issue of foreign ownership of critical infrastructure


Foreign ownership of critical infrastructure has become a topical issue over the last few months as the Australian government suddenly rejected 2 bids for the AusGrid distribution business and now the UK government has put additional safeguards around ownership of nuclear power stations.


A little thought reveals the following confusing and possibly contradictory issues…


·      These concerns are not new. Back in 2008 the NZ government prohibited the sale of a 40% stake in Auckland Airport to the Canadian Pension Plan, and even further back (around 2002) the German government expressed a clear preference for Ruhr Gas to be owned by a German company.


·      Many of the countries that are now expressing concern about foreign ownership have a policy of allowing foreign investment.


·      Free movement of capital is generally expected in today’s global economy, and indeed is one of the founding principles of the European Union. The ability to prevent the sale of ownership stakes would seem to be inconsistent with that free movement of capital.


·      What about the government’s ability to regulate ? There is no shortage of examples of the government regulating and controlling the price, performance and safety of essential infrastructure that it doesn’t own.


US – retiring Diablo Canyon




What we thought were the traditional battle lines over nuclear power have become a bit blurred over the last few years, especially as some factions of the green movement are now advocating for nuclear. This article considers the plans to retire the Diablo Canyon nuclear station in California, and notes the community responses that seem to be advancing that trend of blurring the traditional battle lines.


A bit about Diablo Canyon


Diablo Canyon is a 2 x 1,120 MW pressurised water reactor (PWR) station located near Avila Beach in San Luis Obispo County, about halfway between Los Angeles and San Francisco. Following the start of construction in 1968 the station was completed in 1973. However commissioning of the two units was delayed until 1985 and 1986 respectively after an off-shore seismic fault line was discovered and the reactors were reinforced.


The units are licensed to operate until 2024 and 2025 respectively, after which time they will have both been operating for 39 years.


The retirement plans


In June 2016 Diablo Canyon’s owners, Pacific Gas & Electric (PG&E), announced that it would not seek to extend the operating licenses beyond the current expiry dates. PG&E applied to the California Public Utilities Commission (CPUC) to retire the station and to recover the retirement costs through its regulated electric tariffs.


This announcement came as part of PG&E’s migration from nuclear to energy efficiency, renewables and storage, and saw PG&E align itself with some of its traditional environmental adversaries.


The community’s response to the closure plans


We might well imagine that the surrounding community and environmental groups would welcome the closure, but that’s not what has happened…


·      Six cities in the San Luis Obispo region have filed papers with the CPUC asking them to reject PG&E’s retirement plan. Part of the issue appears to be the loss of property taxes from Diablo Canyon’s operations, for which PG&E proposes to pay $50m compensation.


·      Lobby group Environmental Progress has also filed papers with the CPUC asking them to reject PG&E’s retirement plan, and is claiming that PG&E has inflated the cost estimates of extending the operating licenses to strengthen the business case for closure.


·      Labor unions traditionally support high-paid jobs for their members, and as such don’t obviously align with the anti-nuclear position that some labor unions may align with. The labor unions involved at Diablo Canyon have supported PG&E’s retirement plan, but only after PG&E agreed to a range of benefits including retaining staff for the remaining 9 years, retraining and severance payments.


The wider policy context of the proposed closure


Pipes & Wires #147 examined the passing into law of California Senate Bill 350, which set some very bold energy goals including increasing California’s existing target of 33% renewable electricity by 2030 to 50%, and to double the end use efficiency of electricity and gas consumption. Given the strengthened legislation and PG&E’s apparent plans to implement that legislation, the CPUC might find it difficult to reject PG&E’s retirement plan.


It would be easy to focus on the many parallel threads of detail woven through this issue and be side-tracked by the apparent changes in views, however it is important not to lose sight of the wider issue of changing California’s energy mix, and PG&E’s pro-active plans to lead rather than follow. Pipes & Wires will follow up on this issue in a year or so.


Electricity markets


Aus – are the electricity markets working ?




There will undoubtedly be many views on electricity markets, including how well they are working, and indeed whether they are working at all. This article examines some recent reports from 2 of Australia’s energy regulators which have both concluded that the respective electricity markets are working in different contexts.


The market in New South Wales


Following the introduction of retail competition on 1st July 2014, the Independent Pricing and Regulatory Tribunal (IPART) recently reviewed the performance and competitiveness of the NSW retail electricity market. IPART’s draft conclusions were…


·      Prices have declined, due in part to changes in the underlying cost of supplying smaller customers.


·      The electricity products offered are more innovative and include integrated solar and battery options, energy and communications bundling, more flexible billing arrangements, and shifts away from the traditional kWh-based charges.


·      Six new retailers entered the market during the year ending 30th June 2016 in addition to the five retailers that entered the market during the year ending 30th June 2015. These new entrants are putting downward pressure on the incumbent retailers’ prices.


·      Increasing numbers of small customers are shopping around for their electricity, and potentially saving between $250 and $445 per year.


IPART’s overall (draft) conclusion is that competition in the residential and small business market segments is working well, and that a detailed review of retail prices and profit margins is not necessary.


The market in South Australia


Following some high wholesale prices in South Australia on 7th July 2016, the Australian Energy Regulator (AER) investigated and reported as it is required to do. Figure 3 on pg 10 of the AER report is particularly note-worthy as it clearly shows a pinch point between demand and available capacity around 7pm. The AER’s key findings are…


·      That the interconnection capacity between Victoria and South Australia was materially reduced due to planned outages on the Heywood Interconnector. It appears that while the upgrade work on Heywood was signaled to the market, its implications for reducing interconnection capacity may not have been well understood.


·      The 150kV DC Murray Link was operating near its rated capacity of 220 MW.


·      The closures of the coal-fired Playford B in October 2015 and the coal-fired Northern in May 2016 has increased South Australia’s dependence on gas and wind.


·      Only 20 MW of wind generation was available.


·      The available gas-fired generation was reduced due to both a planned outage at Torrens Island B3, and Pelican Point having been placed on a 48-hour recall in 2015.


·      Limited gas supply and limited gas transmission capacity on 7th July reduced the ability of the remaining gas-fired generation to operate.


The AER’s overall conclusion is that the price spikes were caused by a convergence of operating and structural features, and were not the result of market gaming, lack of competition or abuse of market power.


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 which may be anything up to a few weeks before the date of publication. 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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