From the editor’s desk…
Welcome to Pipes & Wires #154. This month includes a look at a couple of topical gas pipeline issues in New Zealand, and then also looks extensively at the unfolding regulatory and commercial landscape around solar and microgrids.
In amongst all this we examine a transfer of regulatory jurisdiction in Australia, and some wider energy policy issues including closing coal and bringing back nuclear. So … until next month, happy reading…
Recent client projects
Utility Consultants has been involved in the following client projects…
Advice on commercial and regulatory trends
· Client – equipment vendor.
· Location – New Zealand.
· Project – this project involved advising an equipment supplier on the emerging electricity distribution commercial and regulatory trends in the US, how those trends are impacting on solar and battery suppliers and how those trends might translate into the NZ context.
Advice on optimum maintenance resource structures
· Client – hydro and wind generation.
· Location – northern Europe.
· Project – this project involved video conferencing with a client to help them understand the different structural arrangements of maintenance staff and contractors and how those arrangements could create value in terms of improved generator availability, improved productivity and reduced costs. The project included alignment of maintenance policies and strategies with the overall electricity market structure and generation operating strategies.
Assess implications of Code changes
· Client – electricity distribution.
· Location – New Zealand.
· Project – this project involved advising an electricity distributor on how the proposed changes to Part 12A of the Electricity Industry Participation Code could shift costs, benefits, risks and obligations between electricity distributors and retailers.
Mergers & acquisitions
NZ – sale of Maui pipeline completed
Pipes & Wires #149 noted the conditional sale of the Maui Pipeline by the Shell, Todd and OMV consortium to First State Investments for $335m. This article notes the completion of that sale following approval by the Overseas Investment Office (OIO).
Description of the Maui Pipeline
The Maui Pipeline is a welded steel pipeline of approximately 800mm diameter which stretches 307km from Oaonui to Huntly over some very rugged terrain on the west coast of the North Island. The pipeline includes 6 production stations that inject gas directly into the pipeline.
The Maui Pipeline will be both owned and operated by First Gas. The previously separate roles of System Operator, Technical Operator and Commercial Operator will be integrated into First Gas’ overall transmission business.
Regulating the pipelines
Because the former Maui and Vector transmission pipelines were separately owned, they were also separately regulated by separate default price paths (DPP’s). In its Gas Pipeline 2017 DPP Process & Issues Paper, the Commerce Commission expressed its initial view that both transmission pipelines should be covered by one default price path from 1st October 2017 to simplify regulation.
The distribution network will be separately regulated from the transmission pipelines, and separately from the Auckland gas network which Vector retained.
NZ – gas under pressure
The Commerce Commission recent published a paper on implementing the gas pipeline default price-quality paths (DPP) from 1st October 2017. This article recaps the work to date and examines the key proposals of that paper.
Several gas distribution and transmission businesses are subject to default price paths (DPP) which conclude on 30th September 2017. The Commerce Commission has previously published a Process & Issues Paper setting out how it intends to reset that DPP by May 2017 for a commencement date of 1st October 2017
Applicability of the DPP’s
The distribution businesses covered by the DPP include…
· Vector (the legacy Auckland gas network).
· First Gas (the non-Auckland gas networks acquired from Vector).
Both the former Vector and Maui transmission pipelines are covered by 2 separate DPP’s, and it is noted that the Commission has a preference for adopting 1 DPP for both pipelines for the next control period due to their common ownership (First Gas).
Key proposals of the paper on implementing matters
Key proposals of the paper include…
· Changing the form of control for gas transmission businesses from a lagged revenue cap to a pure revenue cap that will include a wash up process.
· Changes to how gas distribution businesses treat pass-through and recoverable costs.
· Introduction of a CapEx wash up recoverable cost for both distribution and transmission businesses.
These are the Commission’s preliminary views which are subject to confirmation following a consultation process. Pipes & Wires will comment further once the final decisions arise.
Aus – transferring regulation of Western Power to the AER
Pipes & Wires #142 examined the announcement by Energy Minister Dr Mike Nahan that jurisdiction for regulating Western Power’s transmission and distribution networks would be transferred from the (WA) Economic Regulatory Authority to the Australian Energy Regulatory (AER). This article examines 3 Bills introduced to Parliament during June 2016 to give effect to this transfer of regulatory authority.
Introducing the proposed legislation
The Barnett Government has introduced the following 3 Bills into Parliament…
The effect of the proposed legislation
The key effect of the proposed legislation is to…
· Make the National Electricity Law, as set out in the National Electricity (South Australia) Act 1996, applicable to Western Australia. This has the further effect of making any regulations pursuant to Part 4 of that Act applicable in Western Australia.
· Make the National Gas Law, as set out in the National Gas (South Australia) Act 2008, applicable to Western Australia. Similar to electricity, this Act will also make regulations applicable to Western Australia.
· Make minor amendments to a wide range of other related legislation to ensure consistency.
Status of the Bills
All 3 Bills have been referred to the Standing Committee on Uniform Legislation and Statutes Review. Pipes & Wires will comment further as the Bills progress through the legislative process.
Solar, batteries & micro grids
US – pushing back against the rooftop solar tariff
There doesn’t seem to be any let up in the struggle between the rooftop solar industry which consistently opposes any shift in the tariff mix, and electric companies who insist that rooftop solar tariffs are necessary to prevent subsidies from non-solar customers. This article examines a recent push back in Texas and New Mexico.
El Paso Electric’s proposed solar tariff
Part of El Paso Electric’s (EPE) most recent rate case (regulatory proposal) application included a proposed $11 per month rooftop solar charge along with a credit of 1.375c / kWh generated against their monthly bill.
The various viewpoints on the proposed tariff
The various viewpoints include…
· EPE stated that the purpose of the charge was to recover the cost of grid connection and usage when solar panels are not generating, and to ensure that customers without solar are not subsidising customers with solar.
· Eco El Paso (a solar advocacy group) has acknowledged that the utility company isn’t doing this to punish, but that it does create a disincentive.
· The Texas Public Utilities Commission (PUC) instructed EPE to re-issue its notice of the proposed tariff increase, allowing effected customers to participate in the rate case decision process. This will delay the effect of the tariff increase sought by EPE.
· The New Mexico Public Regulation Commission approved a tariff increase of $1.1m, much less than both the $8.6m originally sought by EPE and the $6.4m sought in EPE’s revised rate case.
What should we make of this ??
How much real insight and understanding of the issues do the various stakeholder responses reveal ?? My observations are as follows…
· EPE’s responses seem to adequately reflect the true cost of operating the network. Their intention to file a further rate case in 2017 to recover further investment costs validates this.
· To their credit, Eco El Paso’s comments are starting to head in the right direction. The next step will be for them to acknowledge the way in which rooftop solar shifts the recovery of costs from the network.
Pipes & Wires will comment further as the regulatory decisions emerge.
US – the regulatory framework around microgrids
Microgrid technologies are advancing rapidly, possibly a bit too rapidly for the existing regulatory frameworks and decision making processes. This article examines a microgrid proposal by Baltimore Gas & Electric (BG&E) that ran into some regulatory difficulties.
What exactly is a microgrid ?
A microgrid is essentially a sophisticated electricity system that operates at a smaller scale than the large electric grids we know and understand well. A key feature of microgrids is the real-time balancing of demand with supply, including during electric company grid blackouts. Advances in both small-scale generation technologies and microprocessor control technologies have lifted microgrids from a simple emergency diesel generator activated by a relay to new and sophisticated heights.
Most readers will have probably already spotted a couple of key features of microgrids…
· The possibility of back-livening the electric company’s network. Most electric companies require any embedded generation to be clearly notified at the connection point to their network, and for that generation to automatically disconnect and remain disconnected during a network outage.
· The fact that microgrids involve generation may encroach on any vertical disaggregation requirements of generation from networks.
BG&E proposed to install microgrids at 2 village centers that included facilities such as clinics, pharmacies, grocery stores and gas stations for which continued supply during a grid blackout would be useful ... the capacity of the proposed microgrids was about 2MW to 3MW each, and would’ve cost about $16m. In late 2015 BG&E filed a proposal with the Maryland Public Service Commission (PSC) that included a charge of 4c per month to recover the cost of the microgrids.
The opposing arguments
Opposing arguments have come from a couple of different directions…
· Competing electric companies, who claim (quite rightfully on the face of it) that embedding generation undermines the competitive nature of electricity supply and the separation of networks and energy.
· The Microgrid Resources Coalition, who claim that a narrow focus on microgrids providing blackout resilience risks ignoring wider public benefits, primarily customer empowerment.
The Maryland PSC’s response
The PSC’s response has included the following…
· Recommending a wider investigation into microgrid policy.
· Questioning whether the proposal (presumably the inclusion of generation) is legal in Maryland.
· Doubts about whether the public benefits are sufficient to justify funding via an additional monthly tariff.
Unpacking the issues – the editor comments
A couple of issues present themselves here…
· Microgrids, by definition, require the embedding of generation into a network which is likely to contravene the underlying principle of vertical disaggregation in many jurisdictions (separating networks and energy). So any progress with microgrids will require a fundamental re-think on the prohibition of network companies owning generation.
· The Maryland PSC has previously cast doubt on the benefits of BG&E’s smart metering proposal. Readers might remember that BG&E’s smart metering proposal was broadly consistent with Maryland’s energy policy, however when presented with a rate to recover the costs, the PSC concluded that the benefits were largely indirect, highly contingent and a long way off, and rejected the rate case (Pipes & Wires #93 and #94).
Microgrids have at least some potential to benefit customers, however a couple of changes will need to occur…
· A clear policy decision around vertical disaggregation will be required. Either we relax the existing regulatory framework to allow network companies to also own generation (and probably compensate retailers), or we continue to prohibit networks from owning generation. Either way, policy settings in which the only party that is incentivised to do something is also prohibited from doing that very thing simply won’t work.
· Regulators will need to provide clearer ex-ante statements on what emerging technologies they will allow cost recovery from so that electric companies don’t waste time on proposals that will be rejected.
US – rebalancing tariffs and the impact on rooftop solar
The clamor around how rebalancing tariffs in favor of higher fixed charges and lower variable (kWh) charges discourages rooftop solar shows no signs of going away anywhere in the world. This article examines a recent rate (tariff) plan filing by Xcel Energy Colorado.
Xcel’s proposed rate plan
Xcel’s proposed rate plan included the following components…
· A monthly network connection charge, which would range from $2.62 for customers using less than 200 kWh per month to $44.79 per month for customers using more than 1,401 kWh.
· A reduced energy charge of 3.37c per kWh, down from 4.6c per kWh
Xcel estimates that 736,000 of its 1,170,000 customers will have a reduced monthly bill (assuming that their consumption patterns stay the same).
The impact on solar
The benefit of rooftop solar comes in two forms…
· Avoiding the cost of importing kWh from the local network.
· Being paid for exporting kWh to the local network (which is often regulated in the form of a feed-in tariff).
Both forms of that benefit depend heavily on the price of a kWh, and it is readily apparent that reducing the price of a kWh reduces the benefits of rooftop solar. It is this reduction in benefits that the solar industry and its customers are so upset about.
The impact on the network business
The key issue is that the cost of operating a network is almost totally fixed, and independent of the kWh distributed.
The mix of fixed and variable tariffs that most electric companies use to recover their costs are based on some legacy kWh consumption (about 8,000kWh in New Zealand). Significant reductions in kWh consumption (such as what occurs when rooftop solar is installed) obviously reduce that recovery of costs. The options available to the electric company are…
· Accept a reduced revenue, leading to under-funding of each of the building blocks.
· Increase its variable charges. That means that customers with solar benefit even more, encouraging more customers to install solar and further reducing the kWh-based revenue. Meanwhile customers without solar or who can’t afford to install solar simply pay higher kWh charges (noting that many of these customers also cannot practically reduce their kWh consumption).
· Increase its fixed charges. This cannot be avoided by solar customers as an increase in variable charges can be, hence it reduces the subsidy that is observed to occur when variable charges are increased.
An economic perspective on tariff rebalancing
Much is made these days about the economic efficiency of electricity tariffs. So let’s apply a few economic principles and see how the tariff rebalancing stacks up…
· Ramsey pricing - demand for network connections is fairly inelastic, hence network connection should carry most of the margin.
· Cost-reflective pricing - costs are pretty much fixed and independent of kWh consumption, so prices should be as well.
· Dynamic efficiency - given that kWh consumption is likely to decline, realigning the business model away from variable charges would seem to be dynamically efficient.
So from an economic efficiency perspective, it would appear that rebalancing of fixed and variable charges in favor of fixed charges is analytically sound.
NZ – determining the WACC for First Gas
The Commerce Commission recently released its cost of capital decision for any customised price-path (CPP) proposal made by First Gas for its gas transmission services prior to the next CPP WACC Determination in June 2017. This article examines the key features of that determination.
The regulatory framework is set out in clauses 5.3.18 to 5.3.25 of the Gas Transmission Services Input Methodologies Determination 2012.
Key features of the gas transmission WACC’s
Key features of the gas transmission WACC’s include…
Mid-point Vanilla WACC
67th percentile Vanilla WACC
NZ – Orion’s transition back to a DPP
The Commerce Commission has recently released its Draft Electricity Distribution Services Default Price-Quality Path Amendment Determination 2016. This sets out the Commission’s draft decision to transition Orion from its current Customised Price Path (CPP) to the operative Default Price Path (DPP) on 1st April 2019. This article examines the background to Orion’s CPP, and the key features of the draft decision.
Background to Orion’s CPP
The background to Orion’s CPP is as follows…
· Along with the other non-exempt electricity distribution businesses (EDB’s), Orion was subject to the DPP that applied from 1st April 2010 to 31st March 2015.
· Less than 1 year into that DPP a magnitude 6.3 earthquake struck Christchurch on 22nd February 2011, wrecking much of Orion’s network in the CBD and eastern suburbs. The cost of rebuilding the network was beyond what the DPP was able to fund.
· Orion sought an exemption from its DPP by way of an Order In Council as part of a wider body of earthquake recovery legislation, however that request for such an OIC was unsuccessful. Orion were instead told they could apply for a CPP, and moreover that CPP would need to be applied for within the prescribed 2 years following the earthquake (ie. by 22nd February 2013).
· Orion duly applied for a CPP that inter alia requested $155m of CapEx over and above pre-earthquake forecasts.
· The Commission released its Final Decision on 29th November 2013 (refer to Pipes & Wires #129 for the full story).
· That CPP applies to Orion from 1st April 2014 until 31st March 2019, and runs in parallel with the 1st April 2015 – 31st March 2020 DPP that applies to the other non-exempt EDB’s.
· The regulated supplier becomes subject to the DPP that applies to other similar regulated suppliers.
· The starting prices for the DPP are the prices applying at the end of the CPP unless the Commission gives at least 4 months’ notice that different prices will apply.
· The regulated supplier remains subject to the prevailing DPP until either the end of that DPP or a new CPP is sought and granted.
The Commission’s proposed transition back to a DPP
Key features of the Commission’s draft decision include…
· Unless Orion seeks another CPP, it will transition from its CPP to the (amended) DPP on 1st April 2019 and be subject to that DPP for the remainder of its term (until 31st March 2020).
· The expectation that Orion will start the DPP at the same prices it ends its CPP with, excluding any claw back, but with a CPI adjustment.
· The Commission expects to announce its Final Decision in October 2016 after a period of consultation.
The precise legal mechanism is a (draft) amendment to the 2015 – 2020 DPP Determination. Pipes & Wires will comment further once the Final Decision is released.
UK – accelerating the closure of coal-fired generation
Whether the closure of fossil-fired generation will cause the lights to go out has become a hotly disputed topic around the world, with various factions of the green movement claiming that the risk of blackouts has been over-stated by fossil-fired generation operators. This article examines a recent call for the UK to close its’ remaining coal-fired generation by 2023 and questions whether the proposed substitution with gas-fired generation and interconnection is wise.
The call to close coal-fired generation
A recent report by liberal conservative think tank Bright Blue entitled “Keeping the lights on: security of supply after coal” has called for the UK to close its remaining coal-fired generation by 2023 rather than 2025. The report is based around 3 scenarios…
· A base case, in which renewables, nuclear and interconnector capacity increase largely in line with market expectations. Key features include Hinkley Point C opening 3 years behind schedule in 2029, all remaining coal-fired generation closing at the end of 2025, and increased purchase of capacity under the Capacity Market from 2020 to about 2025.
· A low risk scenario, in which renewables, nuclear and interconnector capacity exceeds market forecasts, and demand falls. Hinkley Point C is completed in 2026, whilst all remaining coal-fired generation is forced to close by the end of 2025 or possibly earlier as its viability declines.
· A high risk scenario in which demand increases but new capacity increases are less than forecast. Hinkley Point C doesn’t proceed and all remaining coal-fired generation is closed by 2020.
The reports’ overriding conclusion is that the lights will stay on, even under the high risk scenario. However that is underpinned by the need to commission somewhere between 8,000MW and 21,000MW of gas-fired generation by 2030. The report inter alia recommends that the previous coal-fired generation phase-out date of 2025 should be bought forward to 2023, and that a CO2 emissions performance standard be used to regulate coal-fired generation out of the market.
The proposed substitution of gas for coal
Under the broad theme of examining the UK’s declining reserve capacity margin (Pipes & Wires #116, #143 and #148), the increasing dependence on imported gas from Europe and the declining security of that gas supply was noted. It is not clear that this situation has eased significantly enough to make any gas-fired generation that is built useful.
The proposed increase in interconnection with Europe
Proposals to interconnect the UK with Europe by (additional) undersea cables raises the following issues…
· Possible declines in reserve capacity margins in the countries that the UK might interconnect with.
· The possibility that those interconnects will simply import coal-fired electricity from Europe. That presents the same moral dilemma that Germany faced when on the one hand it decided to close its nuclear stations, but on the other hand kept importing nuclear electricity from France and the Czech Republic.
Wider supply-side issues in the UK
Some of the wider supply-side issues in the UK include…
· The closure of 14 nuclear generators totaling 7,680MW by the end of 2030.
· The difficulties of getting new nuclear generation confirmed, including the range of difficulties still hanging over Hinkley Point C before EDF will commit to construction.
· The plant most likely to be purchased by the Capacity Market will be diesel generators, which will be way more polluting than coal-fired generation.
The editor comments
An analysis of the proposed alternative electricity supplies suggests many additional and increasingly complex risks, mainly associated with plugging into Europe’s gas or electricity. It is not clear that current policy is providing strong enough investment signals for the emerging gap to be closed.
Sweden – bringing back nuclear
Many countries are well down the path of phasing out their nuclear generation, with Sweden being among those furthest along that path. This article investigates the somewhat surprising decision by the Riksdagen to bring back nuclear generation.
Sweden’s progress on phasing out nuclear
Following the Three Mile Island accident in 1979, an advisory referendum was presented to the Swedish people in March 1980. The 3 options presented to voters were actually quite complex and multi-dimensional, and while they embodied preferences for migrating to renewable energy and improving energy conversation, option #3 arguably clouded the issue of nuclear electricity by including nuclear weapons. Notably, there was no option to continue or expand the use of nuclear power, so essentially the referendum was about how quickly nuclear power should be phased out rather than whether it should continue or be phased out. Presumably those who supported nuclear power didn’t get a voice.
Based on voter preferences, the Riksdagen declared that no additional nuclear stations would be built, and that all 12 of the then operational nuclear stations should be closed by 2010 (as it was considered that most of the stations would have remaining lives of about 25 years).
Pressure to accelerate the closures increased after Chernobyl (1986), and in 1988 the Riksdagen decided that the closures should begin in 1995. This decision was over-turned in 1994 due to pressure from the trade unions.
Overtime there has been jockeying amongst the minor political parties, of which the most significant result was a multi-party agreement to close the two 600 MW boiling water reactors at Barsebäck (which occurred in 1999 and 2005 respectively) but to reprieve further closures until 2012 to 2025.
The proposed return of nuclear
A recent agreement signed by the current government and opposition parties includes the following…
· A phase out of the tax on nuclear electricity that was introduced in 1984 and is currently €7.5 per MWh (which generates annual tax revenues of about €465m).
· Allowing the construction of up to 10 new nuclear reactors to replace aging reactors.
· A target of 100% renewable energy by 2040 (which is clearly underscored as a goal, and not as a final cut-off date for the nuclear generation).
Just as a comment, the emerging picture is that a nuclear station takes between 12 and 15 years to plan, approve, design, build and commission, and then might be expected to operate for 40 years to fully recover its costs. So a station approved today (and commissioned in 2030) would be expected to operate for about 30 years beyond the 100% renewable target date. It seems unlikely that there won’t be at least some pressure for early closure which will undermine the investment incentive.
UK – investigating the competitiveness of energy supply
In March 2014 Ofgem concluded that competition in the UK’s retail energy markets wasn’t working as well as it should, and referred the matter to the Competition & Markets Authority (CMA) to investigate. This article follows on from the CMA’s provisional findings that were discussed in Pipes & Wires #153 with an examination of the CMA’s final report.
Scope of the investigation
Just to recap, the investigation focused on the following possible causes of adverse effects on competition (AEC’s)…
· Opaque prices or low levels of liquidity in wholesale markets creating entry barriers.
· Vertically integrated energy companies harming the competitive position of non-integrated energy companies.
· Market power leading to higher prices.
· Weak incentives for energy companies to compete on either price or non-price factors.
Comparing some of the provisional and final conclusions of the investigation
The following table compares the provisional and final conclusions of the
Dispatch of generation plant
Generation plant appears to be dispatched in accordance with the merit order.
Concluded that self-dispatch was not reducing price transparency, increasing costs or introducing technical inefficiency.
Wholesale market prices
Based on an analysis of profitability, the wholesale market price does not appear to be above competitive levels.
Confirmed this view.
Profitability of individual firms
Based on an analysis of profitability, the wholesale market price does not appear to be above competitive levels.
Confirmed this view, reinforcing the view that generators do not have unilateral market power.
Transmission location loss charges
An absence of strong transmission location loss charges.
Confirmed this absence, and noted that this will lead to both short-term and long-term inefficiencies including the possibility of inefficient investment in generation.
Ofgem has urged the industry to implement the CMA’s recommendations for further improvement.
US – is the end in sight for the Boulder muni bid ?
Pipes & Wires has been following the efforts of the City Of Boulder, Colorado to purchase Xcel Energy’s distribution assets and run those assets as a Muni (Pipes & Wires #126, #128, #137 and #141). This brief article notes the recent negotiations between Boulder and Xcel to end Boulder’s bid to form a muni.
Where did the muni’ising process get to ?
After seeking the citizens’ approval through two ballots, the matter ended up in the District Court. The Court ruled inter alia that because the breakup of Xcel’s distribution network could also affect the supply reliability received and the prices paid by Xcel customers outside the Boulder City limits, it was both necessary and appropriate for the Colorado Public Utilities Commission to determine how the distribution systems assets should be allocated.
In amongst the confidential nature of the discussions, statements from both Boulder and Xcel have indicated that more cooperation particularly with renewable energy and customer choice appears to be a better way for Boulder to achieve its initially stated objectives of lower prices and increased renewable energy.
Whichever way the negotiations end up, the balloting process could take until the end of 2017 (noting the idea of a muni was first raised in 2004). Pipes & Wires will comment as the negotiations progress.
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.
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