Canada: Energy @ Gowlings: January 25, 2011

Last Updated: January 26 2011

Edited by Paul Harricks

Contents

  • U.K. Electricity Market Reforms
  • Ontario Energy Board Clarifies Regulatory Status of Connection Recovery Cost Agreements
  • TCPL Mainline - Time for a Public Review?



U.K. Electricity Market Reforms
By Elsa Garagnon

INTRODUCTION

Background

In December 2010, the UK Government launched a consultation process concerning proposals to reform the electricity market. The Energy Secretary described the proposals as a "seismic shift" – and they are, both politically and economically. The proposals aim to deliver the Government's key energy objectives, namely: security of supply, decarbonisation and affordability. The new market framework aims to make low-carbon investment more attractive, encouraging the cost-effective delivery of secure supplies of low-carbon energy from sources such as renewables, nuclear and fossil power stations equipped with carbon capture and storage (CCS) technology.

Underpinning those proposals, is the hope that the UK will become a more attractive country in which to invest. The Government estimates that £110bn (approximately $171bn) in capital investment will be needed by 2020. Of this, £70-75bn (approximately $108-116bn) will go towards investment in new generation capacity, while the rest will cover existing and smart grid infrastructure.

Process

The consultation process currently under way ends on 10 March 2011, except for the consultation on carbon price support (please see "Carbon price floor" section below) which ends on 11 February 2011. Legislative proposals to implement the electricity market reforms will be launched in an "Energy White Paper" in Spring 2011. The Government aims to take news powers in primary legislation "from 2011 onwards" with an aim for the reforms to be in place by 2013/2014.

KEY PROPOSED REFORMS

Carbon price floor

Carbon price support, through a carbon price floor, aims to encourage investment in low-carbon technologies. Introducing a carbon price floor will give greater certainty around the additional cost of fossil generation, thereby making low-carbon power generation more attractive.

The current carbon trading system is the EU Emissions Trading System ("EU ETS") which has been in place since 2005. In that time, the price of carbon under the EU ETS has fluctuated dramatically, particularly in the early phases, making it hard to factor carbon costs into an investment case. A large part of the power generation industry in the UK is subject to this cap-and-trade system with 98% of emissions associated with UK electricity generation being covered by the EU ETS. The EU ETS has created a market in carbon where EU carbon allowances (EUAs) can be traded. From 2013, the EU ETS emissions cap will tighten each year, which should put upward pressure on carbon price. Despite this, the government believes that more certainty about the carbon price is required and that "there is a strong rationale for complementary measures to the EU ETS so as to provide greater certainty".

On that basis, a carbon price support mechanism will be introduced from 1 April 2013. It will be achieved by removing existing Climate Change Levy exemptions relating to fossil fuels used in UK electricity generation and by reducing the amount of fuel duty that can be reclaimed when oil is used to generate electricity. The tax rates ("carbon price support rates") will take into account the average carbon content of the fuel in question. The Government's preferred option is to introduce the carbon price support rates at a different level from the main CCL rates.

Three illustrative carbon price scenarios are set out in the Government's Consultation Paper. In two of these, the amount of carbon price support starts at £1/tCO2, whilst in the third it starts at £3/tCO2 – in each case, on top of the prevailing EU ETS price. This support rises to target a combined carbon price (support plus EU ETS) of, respectively, £20/tCO2, £30/tCO2 and £40/tCO2 in 2020 rising, in each case, to £70/tCO2 in 2030. These figures contrast with the price of carbon in the last 12 months, which has fluctuated between £10 and £14/tCO2. Final decisions on the carbon price support, including the initial levels, will be announced during the March 2011 Budget. In the meantime, the Consultation Paper states that the Government would "welcome views on the appropriate level of the carbon price over the long term".

The Government hopes that introducing a floor on the carbon price will increase long-term certainty about the costs involved in running polluting power plants. However, there is also public concern that supporting the carbon price will increase retail electricity prices and that this will primarily affect low-income households.

The Government's intention is to include these proposals in the 2011 Finance Bill, with secondary legislation to follow.

Feed-in tariffs

Feed-In Tariffs (FITs) were introduced in April 2010 but currently only benefit small-scale electricity generators (below 5MW). The Government now proposes FITs for large-scale generators. The current preferred option is to introduce these FITs by means of a "Contract for Difference" model whereby the Government provides varying levels of support depending on market electricity prices: it would provide support when market prices are low and generators would repay when prices are unexpectedly high. In practice, this would mean that generators sell their electricity into the market, and will then either receive a top-up payment or may have to repay revenues. The top-up payment (or repayment) would be calculated as the difference between the average wholesale market price and the agreed tariff level.

The aim is for the new FITs to provide increased revenue certainty to low-carbon generators, thereby encouraging investment in low-carbon electricity generation. The new FITs would benefit all forms of low-carbon sources, including nuclear but the Government indicated that the FIT could be set at different levels for different technologies. Currently, there is no indication of the levels at which the FITs could be set. The Government is considering various alternatives, in particular premium FITs which could apply to more costly technologies.

Capacity payments

The proposal is to offer payments to power generators for building flexible reserve plants in order to ensure security of supply. Power reserves will be particularly important in the light of the increased amount of intermittent and inflexible power generation.

The Government has indicated that capacity payments could also extend to imports of electricity from European countries and could also cover demand-reduction measures, such as commitments to reduce demand at times of peak demand or intermittent supply.

The Government's current preference is to introduce a volume-based system whereby an obligation would be placed on a central body to maintain a set capacity margin. This body will run tenders for any additional capacity needed to make up the shortfall between the level of spare capacity provided by the market and the centrally-determined margin. This targeted approach would benefit specific generators and could create opportunities for large-scale storage devices.

The Consultation Paper does not specify the extent to which an existing plant (possibly with additional investment) could count as standby capacity but the White Paper may provide further details on this point.

Emissions performance standard

The proposal is for an emissions performance standard to apply to new power stations, which will be designed to set a limit to the amount of CO2 emissions. There already exists a requirement that no new coal-fired plant is built without being carbon capture and storage (CCS)-ready and this new proposal would reinforce the existing requirement.

For now, new gas-fired plants will not be subject to these measures. The Consultation Paper states that the emissions performance standard will be set at a level that will only affect coal-fired plants – though in the long-term the UK will need gas-fired plants to be equipped with CCS technology in order to meet the Government's decarbonisation objective.

COMMENTS

These proposed reforms will help Britain meet some of its legal obligations - in particular, its commitment, under the 2009 EU Renewable Directive, to increasing to 15% by 2020 its energy consumption from renewable sources (which would mean around 30% of its electricity consumption coming from renewable sources) and also its commitment, under the Climate Change Act 2008, to reducing greenhouse gas emissions by 80% before 2050 (compared to 1990 levels).

But today, many power stations are reaching the end of their operational life and it is estimated that around a quarter of all generation capacity must be replaced by 2020. It is hoped that the Government's proposals will encourage the private sector to replace that capacity and invest in capacity to achieve the doubling of demand by 2050.

Regarding renewables projects, the Government proposes that accreditation under the current Renewables Obligation (RO) regime remain open until 31 March 2017. Projects built after that date will benefit from the new Feed-In Tariff system. Pre-2017, any project that is accredited under the RO scheme will continue to receive support for up to 20 years (so potentially until 2037). However, the Government is consulting on whether, pre-2017, generators can opt into the FIT scheme instead.

These reforms, in particular the Feed-In Tariffs, should go some way to making investment in new nuclear more attractive – though some uncertainty remains regarding the costs of construction, decommissioning ageing nuclear plants and disposing of nuclear waste. In the light of the scale of these costs, the Energy Secretary recently declared that, in future, new nuclear plants should be subject to watertight agreements that ensure that these costs do not fall upon the public.

What these proposals mean for investors will be clearer once the process is more advanced – for now, the consensus is that these reforms are much needed and, indeed, the short twelve-week consultation timetable perhaps indicates the Government's keenness to implement them. The Government is aiming to create a stable regulatory framework which gives investors greater certainty on their long-term rate of return from low-carbon generation. Much will depend upon the more detailed proposals which will be contained in the "Energy White Paper". That White Paper will be eagerly-anticipated for those in the power generation industry and we will be reporting in due course on any key reforms relevant to them.



Ontario Energy Board Clarifies Regulatory Status of Connection Recovery Cost Agreements
By Ian Mondrow

In a recent decision issued in a relatively minor application by Hydro One Distribution, the Ontario Energy Board (the Board) has clarified the regulatory status of connection cost recovery agreements entered into between electricity generators and the distribution or transmission utilities to whose systems the generators connect, and of the cost estimates supporting those agreements. The Board has found that connecting generators should be able to rely on the connection cost estimates that the host utility is required to provide in support of the connection cost agreements offered, and should not be charged costs for work subsequently identified as required.

In an application brought at the end of June of last year [EB-2010-0229, Decision and Order dated December 20, 2010], Hydro One essentially sought to clarify how it would recover previously unanticipated but material costs for work required to connect and manage the connection of a number of renewable generation facilities. Hydro One's evidence was that the problems caused in certain connection configurations which were now apparent could not have been reasonably foreseen at the time that the connection agreements with the subject generators were entered into. Hydro One sought recovery of the previously unanticipated costs through the regulatory mechanism for socialization of certain green energy connection costs across all electricity ratepayers in the province.

Hydro One indicated that, should the Board not approve recovery of the costs of the required remediation as it had proposed, it would seek to recover the costs from the connecting generators (though this was not Hydro One's preferred outcome). The Association of Power Producers of Ontario (APPrO) had intervened and argued that seeking payment of these late discovered costs from the connecting generators would be contrary to the principles of fairness. APPrO argued that fairness requires that generators be entitled to rely on the detailed connection cost estimates provided to them in support of the connection cost agreements that they are required to sign in order to move their projects forward. All of the generators in issue in this application had already signed connection cost agreements, based on which they had planned and financed their projects. A number of the projects were already connected and operating.

The Board found that Hydro One should undertake the work necessary to address the remediation requirements identified, and directed that the costs be tracked for subsequent consideration. However, the Hearing Panel determined that it would be guided by earlier policy statements by the Board to the effect that socialization of renewable connection costs would be considered only for projects for which connection costs agreements were executed on or after October 21, 2009, the date that the provisions of the Board's DSC which allow for such province wide recovery came into force. The projects that were the subject of this application all executed their connection cost agreements before the effective date of these DSC provisions. The Hearing Panel rejected arguments that socialization of these costs should nonetheless be permitted since the costs themselves were all prospective, and thus post-dated the effective date of the relevant DSC provisions. However, the Hearing Panel also found that charging these additional costs through to the connecting generators after the fact would be unfair.

The Board found that Hydro One should undertake the work necessary to address the connection concerns identified. The Board directed that the costs incurred should be recorded for future consideration. The Decision indicates that material costs which cannot reasonably be absorbed into Hydro One's existing budgets will be considered for recovery from Hydro One's ratepayers. The Board accepted evidence that the remedial measures will benefit Hydro One customers whose electricity service could be compromised by the technical issues arising as a result of the connection of the subject generators.

Hydro One's application also sought exemption from provisions of the DSC which would have required revocation of capacity allocations that had been granted to generators prior to the date on which the generators received transmission level connection cost assessments. The Board found that additional time is necessary to develop complete connection cost estimates in support of the offers to connect these generators, and granted the exemption requested. The finding on this aspect of the application is consistent with the principle earlier described that generators are entitled to complete and reliable connection cost estimates before being required to execute connection cost agreements. The Hearing Panel recommended that the Board review the rules associated with large generator connections, to ensure the overall integrity of the capacity allocation, connection assessment, cost estimating and connection offer process.



TCPL Mainline - Time for a Public Review?
By Ian Mondrow

In the latter half of 2010 a serious Canadian gas market issue that has been brewing for some years came to a head. The Trans Canada Pipelines Inc. (TCPL) "Mainline" runs from Alberta across the country, and has traditionally brought gas from the western Canadian sedimentary basin (WCSB) to markets in Eastern Canada and the North East United States. A confluence of factors (declining WCSB production, increased intra-Alberta gas consumption, decreasing Eastern Canadian gas demand, and perhaps most importantly competitive gas transportation routes across the continent) have for some years been driving down gas volumes transported through the Mainline. As volumes have declined, and costs have declined less, tolls have risen. As tolls have risen, more volumes have switched to alternative routes and markets, causing volumes to further decline and tolls to rise further, and so on. Some have characterized this pattern as a "death spiral".

For the last few years TCPL has managed to maintain agreement among its shippers to proposed toll levels, and has thus managed to obtain National Energy Board approval for toll changes (generally increases) on the basis of consensus from its shippers. However, late in 2010 this historical shipper consensus broke down.

The substance of the negotiations between TCPL and its shippers is subject to understandings as to confidentiality. It is now, however, a matter of public record that there was significant opposition to the proposal filed by TCPL with the NEB in December for interim tolls as of January 1, 2011. The application filed by TCPL outlined, at a very high level, a number of fundamental changes to the regulatory accounting, cost allocation and toll design model underlying tolls on its Mainline, and tolls on the system of shorter length routes which constitute its "short haul" system within Ontario. The result was a proposal to decrease Mainline tolls, but increase, significantly, short haul tolls. The proposal was presented as based on an agreement between TCPL and the Canadian Association of Petroleum Producers (CAPP). The detailed support for this proposal is to come "early in 2011", but in the interim TCPL requested that the NEB set tolls at the level contemplated by the "agreement" effective January 1, 2011 and on an "interim" basis. Setting tolls on an interim basis would allow them to be made permanent as of January 1 once determinations on final tolls are made by the NEB later in 2011.

While a number of individual stakeholders, including producers and Mainline shippers, supported the interim toll proposal, a number, including short haul shippers and the main gas distributors in Ontario and Quebec, opposed the proposal. In the result, faced with what the NEB has interpreted based on unsolicited submissions made to it as "significant opposition" to the proposal, the regulator rejected the proposed interim tolls. Instead, the NEB declared the current (2010) tolls interim, pending review of a TCPL application for final 2011 tolls.

In its transmittal letter covering the interim tolls order, the NEB "encourages continued efforts to collaboratively address these matters through negotiations with all parties". Unless TCPL is able to modify its proposal to avoid significant increases in short haul tolls while at the same time maintaining decreased and stable Mainline long-haul tolls, it is quite likely that the NEB will receive a hotly contested final 2011 toll application rather than a negotiated proposal. If so, this will be the first time in a long while that the NEB will have to engage in a full review, supported with detailed evidence, of TCPL's Mainline tolls. The looming flood of eastern continent shale gas predicted by most observers (though with different opinions as to the pace and timing for growth in shale gas production) will make the issues facing the Mainline even more difficult, but probably also make a more careful review of Mainline tolls, current and prospective, more important and more timely.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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