Pipes & Wires


Issue 151 – April 2016


From the editor’s desk…


Welcome to Pipes & Wires #151. This month starts with the completion of a major merger in the US, and then looks at some gas regulatory decisions in the UK and NZ. We then look at some renewable energy issues in the US and conclude by examining 3 nuclear issues in South Africa, the UK and France. So … until next month, happy reading…


Mergers & acquisitions


US – the Exelon – Pepco merger gets final approval




The Exelon – Pepco merger received its final regulatory approval in March 2016. The Washington DC Public Service Commission (PSC) voted 2 – 1 to allow the merger to proceed, creating the largest electric company in the US.


The PSC approval


Readers will have noted from previous issues of Pipes & Wires that getting the Washington DC PSC’s approval was a drawn out process with various lobby groups, customer advocates and government agencies objecting to the merger. This resulted in a revised merger proposal being submitted to the PSC which received their approval.


The merged company


Exelon is among the largest of America’s electric companies, with about 35,000 MW of generation supplying about 7,800,000 customers through its subsidiaries Baltimore Gas & Electric, Commonwealth Edison and the Philadelphia Electric Company (PECO). Annual revenues are about $25b.


Pepco Holdings supplies about 2,000,000 electric and gas customers in the Delaware, Washington DC, Maryland and New Jersey areas through its regulated subsidiaries Pepco, Delmarva Power and Atlantic City Electric.


The merged company will supply about 9,800,000 customers and have annual revenues of about $29b.


More information on the merger


Check the following references for more information on the merger…


·      Timeline of the merger.


·      Pipes & Wires #134, #136, #140, #141, #142, #144, #145, #146, #147 and #150.


·      Pepco’s merger website.


Closing comments


Phew … this has been a long one, especially obtaining final approval in Washington DC. Pipes & Wires will comment further as Exelon and Pepco integrate their activities.


Regulatory decisions


UK – measuring the regulatory performance of gas businesses




This article looks at Ofgem’s recent performance assessments for the UK’s gas transmission and distribution businesses for the year ending 31st March 2015.


The RIIO regulatory framework


A few years ago the UK gas & electricity regulatory Ofgem introduced the RIIO regulatory model on 1st April 2013 following the decision that the former RPI-X model had worked well enough but that a better model was needed for the future (refer to Pipes & Wires #69, #94 and #101). This model is based on business outcomes of safety, reliability and customer satisfaction rather than focusing on inputs such as capital and operating costs.


The UK’s gas networks


The UK’s gas is supplied by the following networks…


·      The gas transmission pipelines are owned by National Grid Gas Transmission.


·      The gas distribution networks are owned by 4 companies … National Grid Gas, Northern Gas Networks, Wales & West Utilities, and Scotia Gas Networks.


Ofgem’s report on gas transmission


Key features of the gas transmission networks report include…


·      The required customer satisfaction, connections and environmental performance has been met.


·      The review of a serious incident is awaited before NGGT’s safety performance can be determined.


·      Ofgem is of the view that NGGT’s final under-spend for the 8 year regulatory period should be greater than what NGGT has forecast due to the amendment and deferral of several major capital projects.


Ofgem’s report on gas distribution


Key features of the gas distribution networks report include…


·      A forecast out-performing of the cost allowance by £2.1b over the 8 year regulatory control period, of which the gas companies will get to retain 64% with the other 36% being returned to customers through lower prices.


·      All safety outputs are being achieved except for National Grid Gas Distribution’s management of repair risk.


·      Although network availability was 99.997%, Ofgem has some concerns that some aspects of the reliability targets may be unachievable whilst other aspects may encourage undesirable behavior (eg. scheduling repair work to suit the gas company rather than the customer).


·      In regard to customer satisfaction there was a mix of over-performance for emergency response and repairs, but an under-performance for planned interruptions.


Some comments about RIIO


Two features of RIIO standout…


·      Most obviously, an emphasis on high-level outputs whilst letting the gas companies manage the internal tradeoffs between cost, work programs and performance themselves.


·      Less obviously, an 8 year regulatory period that provides gas companies with greater flexibility to re-shuffle work programs and engage contractors.


So the big question is … is RIIO working, or perhaps more specifically is RIIO working better than RPI-X ??  It’s obviously early days (only 2 years into the first 8 year period) but it appears that a focus on outcomes that really matter to customers and their communities seems to be working.


NZ – gas under pressure




The Commerce Commission recently released its cost of capital decision for any customised price-path (CPP) proposal made by Powerco for its gas distribution business prior to the next CPP WACC Determination in March 2017. This article examines the key features of that determination.


Regulatory frameworks


The regulatory framework is set out in clauses 5.3.22 to 5.3.29 of the Gas Distribution Services Input Methodologies Determination 2012.


Key features of the gas distribution WACC’s


Key features of the gas distribution WACC’s include…



3 year

4 year

5 year

Mid-point Vanilla WACC




67th percentile Vanilla WACC





NZ – decision not to inquire into gas metering services




One of the key functions of any economic regulator is to ensure that markets don’t become dominated by a small number of suppliers, who might then increase prices or reduce service levels. This article examines the Commerce Commission’s recent decision not to inquire into whether gas metering services should be regulated.




In October 2012 Vector sought the Commission’s approval to acquire Contact Energy’s gas metering business. The Commission approved Vector’s application in April 2013 (Pipes & Wires # 122), and noted the following issues…


·      It appeared that there was already limited competition between Vector, Contact Energy and the other suppliers of gas metering services.


·      A comparison of the market both with and without the acquisition suggested there would be no significant difference in the levels of competition.


The Commission has, however, remained concerned about the level of competition having previously noted that Vector and Powerco control about 96% of the market for gas metering services.


The Commission’s decision


In April 2016 the Commission decided it would not inquire into gas metering services pursuant to Subpart 2 of Part 4 of the Commerce Act 1986, but would continue to monitor the price of such services in the future. The reasons for the Commission’s decision was that the benefits of regulation would be unlikely to out-weight the costs of an inquiry and any possible subsequent regulation … analysis suggested that the saving might be between $0.63 and $1.03 per month for an average consumer.




US – Nevada PUC faces law suit over solar decision




The Alliance for Solar Choice (TASC) recently filed a law suit against the Nevada Public Utilities Commission (PUC) in regard to the PUC’s recent approval of Nevada Power’s tariff realignments.




Pipes & Wires #149 examined the big hit that rooftop solar took in the US state of Nevada as the PUC approved Nevada Power’s plans to increase its monthly connection tariff whilst also significantly reducing its feed-in tariff. This tariff re-alignment included the added dimension of applying to existing rooftop solar customers ie. no grandfathering.


The sequence of events to date


The sequence of events includes…


·      Nevada Power sought the PUC’s approval to increase its monthly fixed connection charge from $12.75 to $17.90 on 1st January 2016 and then to $38.51 on 1st January 2020, and to also reduce its feed-in tariff from 11c per kWh to 9c per kWh on 1st January 2016 and then to 2.6c per kWh on 1st January 2020.


·      The Alliance for Solar Choice (TASC) requested the Nevada Public Utilities Commission to delay the new tariffs that were scheduled for 1st January 2016.


·      The staff of the PUC recommended that the request to delay be denied ie. Nevada Power will be allowed to proceed with the tariff increases.


·      Solar advocates claim that the PUC’s decision will mean the end of the solar industry in Nevada, and indeed one supplier (Solar City) has announced it will no longer supply or install solar in Nevada.


·      After extensive outcry from the solar industry, the PUC revised its decision with a view to requiring grandfathering of existing solar tariffs, meaning that the proposed ramping up of the monthly tariff to $38.51 would occur by 2028 instead of 2020.


TASC’s law suit


Information on the precise basis for TASC’s law suit seems hard to find. There are a couple of readily observable facts such as the PUC decision being a “big win for the utility at the expense of solar users”, and “unless relief is granted by the court, rooftop solar power generation may well cease to exist in Nevada”, but there don’t seem to be any obvious points of law. Some might even say it sounds like a “sob … sob … we didn’t get our way” sort of thing.


Why is this law suit so significant ??


Electric companies are at a crossroads in regard to a raft of issues around rooftop solar and who pays how much to connect and inject. Nevada had apparently reached a position where customers with rooftop solar would pay monthly connection charges and be paid feed-in tariffs that (i) reflect the electric company’s costs, and (ii) don’t extract a subsidy from non-solar customers. This law suit seeks to over-turn what appears to be an analytically sound decision on the basis of “it’s not fair”.


US – going for 100% renewables in Hawaii




The Governor of the US state of Hawaii recently signed House Bill 623 into law mandating 100% renewable energy by 2045. This article unpacks exactly what HB623 will require, how the energy industry might achieve it, and what the price and reliability trade-offs are likely to be.


What exactly does HB623 require ??


Essentially HB623 requires a ramping up of the percentage of renewable electricity sold by each electric company as follows…



Percentage to be renewable

31st December 2020


31st December 2030


31st December 2040


31st December 2045



The remarks preceding the above table in HB623’s text note that the goal of extending the renewable portfolio goals beyond 2030 should be subject to the following considerations…


·      It must benefit the Hawaiian economy.


·      It must benefit all electric customers.


·      It must maintain customer affordability.


·      It does not induce renewable energy developers to artificially increase the price of renewable energy in Hawaii.


These remarks suggest that the Hawaiian government has recognised the affordability issues that have arisen in other jurisdictions, and is providing for a useful “pause and consider” at around 40% renewables penetration.


Where is Hawaii at with renewable penetration ??


Historically about 75% of Hawaii’s electricity has been generated by oil-fired plant, with a further 15% generated by coal-fired plant and the remaining 10% from renewables. Those oil and coal imports have understandably resulted in high electricity prices, in fact the highest in the United States being some 20% higher than the next most expensive.


During the 2014 year, grid–scale renewable generation climbed to 13% (including bio-mass and geothermal), with a further 8% from small-scale renewables. So in broad terms Hawaii is at about 20% renewables.


What specific initiatives will be required to achieve 100% renewables ??


Well obviously there is going to have to be a significant migration from oil-fired and coal-fired generation to renewables. A little research reveals the following…


·      About 50% of Hawaii’s generation capacity (MW) is intermittent … about 1,465MW of the total 2,785MW.


·      There is about 145MW of potential hydro sites. The fact that many of these sites were identified up to 40 years ago suggests they are unviable viz-a-viz historical and current prices.


·      There appears to be very limited potential for further geothermal development over and above the 60MW of existing and planned capacity.


This would suggest that future renewable investment will need to be mainly wind and solar, which is of course intermittent. This will be compounded by a lack of quick-start generation to buffer those renewables, and then possibly further compounded by the rapid life consumption of the oil and coal-fired steam turbines if they are used to follow load profiles.


What reliability and price trade-offs are likely to result ??


The above analysis suggests that achieving the required renewables penetration will require significant amounts of intermittent generation. This requires the state of Hawaii to make some strategic choices along the following lines…


·      Build sufficient “installed capacity” to meet “maximum demand”. This choice embodies an acceptance that the lights will go out when the wind stops blowing or clouds cover the sun.


·      Build extra capacity based on the likely availability of wind and solar plant. This choice embodies a much higher cost which will need to be recovered from customers.


Either choice will almost certainly result in a significant shift from the existing reliability-price trade-off (as any movement on the energy trilemma does). As noted above, the legislation includes what appears to be a “pause & consider” at about 40% renewable penetration but it is not clear that there is a full awareness of exactly how tough that choice might be.


Nuclear energy


South Africa – progress on the nuclear station




South Africa’s National Nuclear Regulator recently received 2 site license applications from Eskom ahead of the government’s expected RFP for new nuclear generation. This article looks back over South Africa’s recent moves toward additional nuclear capacity and examines Eskom’s applications.


Recent moves toward additional nuclear capacity


After operating the Koeburg nuclear station since 1984, the South African Energy Minister Dipuo Peters signed off a proposal for 9,600MW of nuclear capacity that would see commissioning by about 2024 or 2025. The likely cost is estimated to be between R400b and R1,000b.


Eskom’s proposed sites


Eskom’s proposed sites are…


·      Thyspunt, in the Eastern Cape.


·      Duynefontein, in the Western Cape just north of Koeburg.


The various responses


Not surprisingly, there have been a wide range of responses…


·      Eskom is confident that it can fund, build and operate new nuclear stations.


·      New Nuclear Watch Europe expressed confidence in the safety of nuclear, and noted the comparability of total life-cycle costs with coal-fired stations.


·      NERSA has not done any modelling of the impact on tariffs, indicating that it would take up to 15 years to get the first unit operational.


·      Rating agency Moody’s seem nervous about how the cost of building 2 nuclear stations will impact on Eskom’s credit worthiness.


·      The latest World Nuclear Industry status report paints a less than optimistic picture of declining nuclear operation and government hesitancy over new nuclear generation.


Next steps


As noted above, the next step is the release of the RFP. A key issue will be the electricity sector’s interest in that RFP … Pipes & wires will comment as that interest becomes apparent.


England – progress on Hinkley Point C




EDF Energy’s proposed Hinkley Point C nuclear station has featured in the news recently, so Pipes & Wires thought it was time to have another look at this and try to scratch through some of the media hype and get to the real issues.


The major issues to date


A couple of the major issues to date include…


·      The escalating cost. The publically stated costs have increased from an initial £10b through a series of significant increases to £24.5b, although recent media reports are saying about £18b.


·      Technical difficulties arising during the construction of the Flamanville #3 reactor in France which is using the same 1,600MW European Pressurised Reactors (EPR) proposed for Hinkley Point C. It has been suggested that any decision on Hinkley Point C should be deferred until at least 2019 when the realities of Flamanville will be clearer.


·      The drawn out process of obtaining a 35 year Contract For Differences funding model that will provide certainty of investment (funny … if it was a solar panel there would’ve been no trouble getting that certainty of investment).


·      An investigation by the EU to determine whether the CFD funding model breached the EU prohibition on state aid. An amended model was finally approved by the EU.


·      A challenge to that decision by Austria and Luxembourg claiming that any state aid must be targeted towards renewable energy.


·      On-going criticism that the finally agreed price of £92.50 per MWh guaranteed for 35 years with inflation adjustments (3x the current price) is just plain crazy.


·      An internal report to the EDF Energy board warning that it would technically impossible to complete the 2 reactors by the proposed 2025 completion date.


·      A board level suggestion that the whole Hinkley Point C project will be financially ruinous for EDF Energy’s parent company EDF. This resulted in the resignation of EDF’s finance director who was a firm critic of the project.


·      Moody’s noted that EDF’s declining operating cashflow resulting from softer electricity prices and existing debt obligations may further exacerbate the risks associated with Hinkley Point C.


Current status of the decision


So … where does that leave it ?? Amongst a quagmire of engineering, financial and political difficulties EDF officials and ministers of the French government have given strong assurances to the UK government that Hinkley Point C will “definitely proceed” even if the French government has to recapitalize EDF. A further announcement is expected in a few months….


France – what exactly is happening at Flamanville ?




Most recent discussions about new nuclear generation seem to stumble across Flamanville with vague utterances about “engineering difficulties”, “delays” and “cost increases”. This short article takes a look at the Flamanville #3 reactor and tries to uncover exactly what the issues are.


The existing Flamanville power station


The existing Flamanville station has two 1,300 MW Pressurised Water Reactors (PWR’s) that were placed into commercial operation in 1986 and 1987 respectively. The station is located near the village of Flamanville in the Manche area of north-western France.


The reactor type being installed


The third reactor being installed at Flamanville is a 1,600 MW European Pressurised Reactor (EPR) designed by Areva. Construction began in December 2007 with an expected completion of about April 2012. Then came a series of cost escalations and completion delays, with the estimated start date now being late 2018.


The specific problems


Pipes & Wires #145 noted the following 2 technical problems…


·      Reduced mechanical strength of the pressure vessel head due to high carbon concentrations.


·      Discovery of multiple malfunctioning relief valves on the reactor vessel.


Expanding on the first point, tests performed in 2014 revealed that some zones of the reactor vessel and cover included significant concentrations of carbon. Those concentrations of carbon reduce the resilience of the steel and reduce its ability to resist crack propagation.


The regulator’s decisions


Areva informed the French Nuclear Regulator (ASN) which said that it would consider Areva’s proposed remedial actions and issue a decision, which is now not expected until the end of 2016. That decision is expected to delay commercial operation until late 2018, with the possibility that a worst-case decision by the ASN requiring replacement of the vessel could add further delays and costs.


The costs and delays


The cost and expected completion dates are approximately as follows…


Date of announcement

Expect cost

Expected completion date

December 2007 (original announcement)


April 2012

December 2012



September 2015


Late 2018


So the latest estimates are 6½ years of delays and €7.2b of cost over-runs.


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.