Pipes & Wires

THE JOURNAL OF ENERGY & INFRASTRUCTURE THOUGHT LEADERSHIP

Issue 103 – July 2011

 

From the editor’s desk…

 

Welcome to Pipes & Wires #103. This article starts by examining a major re-think of corporate strategy in Europe, and then reviews 4 regulatory decisions (well, okay 3 decisions and 1 proposal). We also catch up on a couple of mergers in the US and examine some regulatory policy issues, including a bit of widening of scope to look at the next UK rail price reset.

   

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Matters for attention

 

NZ – public safety management systems

 

Just a reminder that the requirement for all electricity businesses (of more than 10MW capacity) to have their PSMS in place and externally audited is only 8 months away. For help with compiling your PSMS, or to have a pre-audit review undertaken, phone Phil on (07) 854-6541 or pick here.

 

Corporate strategy

 

Global – revisiting E.On’s strategy

 

Introduction

 

Over the years Pipes & Wires has examined German utility E.On’s “On Top” strategy which set out a global growth plan based on 5 key geographical platforms. On the back of recent reversals to that strategy, this article takes a closer look at E.On’s much revised strategy. 

 

The original “On Top” strategy

 

The core of the “On Top” strategy was to grow five well defined markets principally through acquisition as follows…

 

Market

Emphasis

Platform

Pan-European gas transport and storage.

Acquiring privatised gas transmission utilities in the former Soviet-bloc.

Ruhrgas

Central European electricity market.

Consolidation of distribution and retail businesses.

E.On Energie

Scandinavian electricity.

Strengthening market position through further acquisitions.

Sydkraft

UK electricity.

Strengthening market position through acquisitions.

Powergen

US mid-west electricity.

Long-term expansion.

LG&E Energy

 

A guiding principle of “On Top” is to systematically capture the synergies implicit in all acquisitions and ensure those synergies are returned to shareholders

 

Reversing the strategy

 

For a long while it appeared that the disciplined approach of “On Top” would safeguard E.On’s long-term future, especially when compared to its most visible rival, Electricité de France (EDF). However a few telling signs began to emerge ... re-thinks on apparently sound acquisitions, and then divesting of grid assets such as LG&E – KU, Central Networks and Transpower Stromübertragungs GmbH (and it is acknowledged that some asset sales were regulatory concessions rather than strategic realignments).

 

The wider context

 

In the wider context, other network businesses began to be sold or at least packaged for sale ... EDF sold its UK distribution businesses, whilst RWE packaged up its’ UHV grid RWE Transportnetz Strom into a subsidiary called Amprion. Pipes & Wires #88 hypothesised that this was an emergence of a preference for selling lines and retaining energy.

 

The current strategy

 

E.On had previously announced that it wanted to raise €15b from asset sales by the end of 2013, and it now appears that grids will be the key part of that asset sale strategy. From E.On’s perspective grids represent a high CapEx spend requirement coupled with low growth levels which would strengthen the case for migrating capital to unregulated businesses. Having said that, grids and networks do offer predictable, inflation proofed, returns that make them attractive to both pension funds and municipalities (which wouldn’t ordinarily have ready access to high-growth unregulated markets other than through investing in electric utilities).

 

Possible next moves

 

So ... what might E.On’s next move be ?? A couple of possible thoughts spring to mind...

 

·       Sale of minority (non-strategic) stakes in distribution networks where E.On cannot extract synergies. E.On has many such stakes both in its home turf of Germany and in the former communist states in eastern Europe.

 

·       Sale of transmission grids that link E.On’s existing or potential future retail markets with E.On’s low-cost coal-fired plants. These coal-fired plants may have an even greater role to play as Germany’s nuclear stations are closed.

 

Pipes & Wires will check back on this as various deals and announcements emerge.

 

Regulatory decisions

 

Aus – the Queensland gas distribution final decision

 

Introduction

 

Previous issues of Pipes & Wires (#96, #99 and #100) have examined APT Allgas’ proposed Access Arrangement for its’ Queensland gas network (which also crosses into NSW) for the period 1st July 2011 to 30th June 2016. This article concludes that examination with a summary of the Australian Energy Regulator’s (AER) Final Decision.

 

Key aspects of the revised Access Arrangement

 

Key aspects of the process are set out in the following table...

 

Parameter

Proposed AA

Draft Decision

Revised AA

Final Decision

Total OpEx

$110.12m (nominal)

$102m (nominal 10/11)

$93m (nominal 10/11)

$115m (nominal)

$107m (nominal)

Total CapEx

$139.05m (nominal)

$129m (nominal 10/11)

$125m (nominal 10/11)

$145m (nominal)

$128.9m (nominal 10/11)

Opening capital base

$421.6m (nominal)

$424m (nominal)

$424m (nominal)

$427m (nominal)

Closing capital base

$559.9m (nominal)

$562m (nominal)

$551m (nominal)

$554m (nominal)

Rate of return

10.3% (post-tax nominal vanilla)

9.96 (post-tax nominal vanilla)

11.38% (nominal vanilla)

9.50% (nominal)

Debt risk premium

3.85%

3.93%

4.69%

3.64%

Revenue requirement

$372.1m (nominal)

$345m (nominal)

$348m (nominal)

$361m (nominal)

 

This concludes Pipes & Wires coverage of APT Allgas for the next few years.

 

Ireland – the transmission grid asset owner price controls

 

Introduction

 

Back in November 2010 the Commission for Energy Regulation (CER) issued its final decision on the revenue that ESB Networks would be able to recover via its Transmission Use of System (TUoS) agreements over the 3rd control period (PR3) from 1st January 2011 to 31st December 2015. This article examines that final decision, but more from an issues perspective rather than tabulating the € like what we’ve done for the Australian decisions.

 

The wider context for PR3

 

The wider context for PR3 includes....

 

·       An increase in extension CapEx to connect new renewable generation.

 

·       An increase in renewal CapEx as an increasing volume of assets reach the end of their useful lives.

 

·       An expectation that further operational efficiencies will be achieved.

 

So far there wouldn’t appear to be anything unique to Ireland about these features.

 

The key components of PR3

 

Key components of PR3 include....

 

·       A requirement to make an efficiency gain of €16.2m over 5 years embedded within the total allowable revenue of €921m. The CER has not specified how these efficiencies are to be achieved.

 

·       Inclusion of an annual CapEx monitoring program and a cost-benefit template for all CapEx projects over a yet-to-be-defined figure to ensure efficient delivery.

 

·       A recognition that the determined WACC must allow ESB Networks to competitively access the global capital markets to fund its CapEx program.

 

·       Consideration of a move away from the classical deterministic planning approach of (n-1) security to securing demand with local generation.

 

·       Consideration of using surplus network capacity to transmit injected wind power.

 

PR3 embodies a couple of features that are not obvious in other transmission decisions, in particular the “unspecified efficiency gains” and the move away from securing demand with grid capacity. The CER will be undertaking a mid-term review of PR3, so that’s probably a good time to see how things are starting to work out.

 

Aus – the Queensland electricity grid regulatory proposal

 

Introduction

 

Transmission grid owner Powerlink recently submitted its Regulatory Proposal to the Australian Energy Regulator (AER) for the 5 year control period beginning on 1st July 2012. This article summarises the key features of that Proposal to set some context for future analysis of the draft and final decisions.

 

Legal framework

 

The primary legal framework is the National Electricity Law (NEL) which is given legal effect in each jurisdiction of the NEM by individual state laws. The NEL provides for the National Electricity Rules (NER) to be promulgated, with Chapter 6A applying specifically to the economic regulation of transmission services.

 

Key features of Proposal

 

Key features of Powerlink’s proposal include...

 

Parameter

Proposal

Draft decision

Revised Proposal

Final decision

Total OpEx

$1,002m

 

 

 

Total CapEx

$3,484m

 

 

 

Opening capital base

$6,579m

 

 

 

Rate of return

10.3%

 

 

 

Revenue requirement

$5,954m

 

 

 

 

Pipes & Wires will revisit this when the AER releases its draft decision.

 

Aus – South Australian gas distribution final decision

 

Introduction

 

Previous issues of Pipes & Wires (#96, #99 and #100) have examined Envestra’s proposed Access Arrangement for its’ South Australian gas distribution networks for the period 1st July 2011 to 30th June 2016. This article concludes that examination with a summary of the Australian Energy Regulator’s (AER) Final Decision.

 

Key aspects of the revised Access Arrangement

 

Key aspects of the process are set out in the following table...

 

Parameter

Proposed AA

Draft decision

Revised AA

Final decision

Total OpEx

$335.69m (real 08/09)

$344.1m (real 10/11)

$260m (real 10/11)

$336m (real 09/10)

$305m (real 10/11)

Total CapEx

$506.9m (real 08/09)

$520m (real 10/11)

$415m (real 10/11)

$507m (real 08/09)

$494m (real 10/11)

Opening capital base

$1,030m (nominal)

$1,018m (nominal)

$1,030m (nominal)

$1,024m (nominal)

Closing capital base

$1,595.4m (nominal)

$1,420m (nominal)

$1,595.4m (nominal)

$1,514m (nominal)

Rate of return

10.64% (nominal post-tax)

9.96% (nominal post-tax)

10.98 (nominal)

9.77% (nominal)

Debt risk premium

3.39%

3.93%

4.67%

3.81%

Revenue requirement

$1,165m

$985m

$1,165m (nominal)

$1,049m (nominal)

 

This concludes Pipes & Wires coverage of Envestra’s distribution business for the next few years.

 

Mergers & acquisitions

 

US – follow up on AES’s acquisition bid for DPL

 

Introduction

 

Pipes & Wires #101 introduced AES’ recent $4.7b acquisition bid for Dayton Power & Light (DPL). This article examines a couple of recent issues that have emerged.

 

Background to the deal

 

This deal is fairly simple ... AES will pay $30 cash for each share of DPL’s common stock (which represents about an 8.7% premium to DPL’s closing price on the day of announcement) and assume $1.2b debt. Key drivers of the deal include:

 

·       The need for AES to reduce its high exposure to declining wholesale electricity prices by forward integrating into a retail customer base. However this may only buy about 18 months of high prices as DPL’s current regulated retail price (which is about 25% higher than market prices) expires in late 2012.

 

·       The need for AES to improve the returns on its cash reserves.

 

·       DPL’s strength of future earnings due to pre-existing emission controls on its coal-fired plants.

 

·       Possible synergies between DPL and AES subsidiary Indianapolis Power & Light.

 

Recent issues

 

Recent issues to emerge include:

 

·       Likely credit downgrades for both the parent DPL and the subsidiary Dayton Power & Light as both Moody’s and Fitch’s anticipate AES raising about $1.25b debt to fund the share purchase, and then allocating that debt to DPL thereby increasing its debt load to about $2.45b.

 

·       The DoJ and the Federal Trade Commission (FTC) granted an early termination of the waiting period required under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.

 

The approval of inter alia the FERC, the Public Utility Commission of Ohio and DPL shareholders is still required so Pipes & Wires will make further comment as those approvals emerge.

 

US – regulatory hurdles for the NU – NStar deal

 

Introduction

 

Late in 2010 Northeast Utilities launched a $4.17b bid for NStar, whilst earlier this year the deal encountered 2 unexpected regulatory hurdles. This article examines those hurdles, checks out the latest thinking on those hurdles and then discusses what that might mean for future deals.

 

Hurdle #1 – the Connecticut DPUC’s jurisdiction

 

The Connecticut Department of Public Utility Control had originally concluded that under state law the DPUC’s approval was only required when a new holding company would gain control over a state utility, and that in this case there was no new holding company (NU was not changing, simply acquiring another company). However the Attorney General, the Senate President and the Office of Consumer Counsel (OCC) argued that NStar would exert significant control over the enlarged NU so although there was technically no new holding company, it could be argued that NU was kind of a new company (and therefore subject to approval).

 

In early June 2011 the DPUC concluded that state law does not allow it to intervene in the deal because inter alia the 2 NU subsidiaries in Connecticut (Connecticut Light & Power and Yankee Gas) would still be subject to its jurisdiction. The OCC expressed its disappointment with that conclusion, and in early July went to court to appeal the DPUC’s decision. However the arguments proposed by the OCC as to why the DPUC should intervene in the deal would appear to be already well covered by the DPUC’s on-going powers to regulate those utilities.   

 

Hurdle #2 – the Massachusetts DPU’s increased burden of proof

 

The Massachusetts Department of Public Utilities sought to impose a “demonstrate net benefits to customers” burden of proof rather than the “no net harm to consumers” criteria that has been used previously. Prima facie, NU and NStar have publically quantified the merger benefits as well as confirming that grid investment and clean energy initiatives will proceed, so this issue would appear to hinge not so much on the creation of benefits, but rather the sharing of those benefits with customers. However some concerns have been raised that the merger could reduce electricity purchasing competition.

 

As of mid-July, the MDPU has commenced a series of hearings around the burden of proof (and it appears that many more issues will become entwined in the hearings). Pipes & Wires will comment further as the hearings conclude.

 

US – Gaz Metro beats Fortis to Central Vermont

 

Introduction

 

Pipes & Wires #102 examined Canadian utility Fortis’ bid for the Central Vermont Public Service Corp (CVPSC). This article briefly examines a competing bid from Gaz Metro Limited Partnership, and notes that CVPSC accepted the Gaz Metro bid and terminated the Fortis bid.

 

Recapping Fortis bid

 

The key features of Fortis’ bid are....

 

·       A cash offer of $35.10 for each CVPSC share, valuing CVPSC’s equity at $470m.

 

·       Assumption of $230m of debt.

 

·       A premium of 44% over CVPSC’s closing price on the NYSE.

 

Examining Gaz Metro’s bid

 

Montreal-based Gaz Metro’s bid had the following key features...

 

·       A cash offer of $35.25 for each CVPSC share, valuing CVPSC’s equity at $472.4m.

 

·       A premium of 45% over CVPSC’s closing price on the NYSE.

 

The wider picture of Gaz Metro’s bid

 

Gaz Metro began in the 1890’s as the Natural Gas Corporation of Quebec by lighting the streets of Montreal. Since then it has grown to encompass the whole gas value chain, and has also acquired Vermont Gas Systems in 1996 and Green Mountain Power (GMP) in 2007 (both in the US state of Vermont).

 

That ownership of GMP would appear critical to this deal, as GMP neighbors CVPSC. Hence Gaz Metro will be able to extract merger synergies that (presumably) Fortis’ would not have been able to, and therefore justifies Gaz Metro paying a slightly higher price. The merged entity will have about 256,000 electric customers across Vermont, and will provide opportunities for about $144m of cost savings over 10 years as well as investment in renewables.

 

As previously noted, the deal will be subject to regulatory approval.

 

Regulatory policy

 

UK – setting the framework for the next rail price reset

 

Introduction

 

It’s been a while since Pipes & Wires examined the regulated rail sector, so a recent consultation paper from the Office Of Rail Regulation (ORR) in the UK sparked my interest. This article examines the Periodic Review 2013 (PR13) paper that will shape the outcomes and access charges Network Rail will be expected to deliver during the 5th Control Period (CP5) starting on 1st April 2014 (with a yet-to-be-determined end date).

 

Wider priorities feeding into PR13

 

Some of the wider priorities that will feed into PR13 include....

 

·       An expectation that the industry will improve its efficiency by about 30% by 2018/19 (compared to the 2008/09 baseline).

 

·       The devolution of rail maintenance and repair from Network Rail to train operators.

 

·       Letting rail asset management concessions to 3rd parties to encourage efficiencies and provide comparative performance data.

 

·       A disaggregation of management activity to a route level, enabling more transparency and better comparison of costs.

 

·       A migration toward longer franchises and more flexible specifications to ensure that Network Rail and the train operator’s incentives are better aligned.

 

·       The expectations of the governments of both England & Wales, and of Scotland (these will be fed into PR13 as the High Level Output Statements (HLOS’s) in July 2012), and the level of funding they will provide.

 

What will CP5 look like ?

 

The key elements of CP5 will include....

 

·       The use of a building block model, similar to most other regulated infrastructure.

 

·       Operational (but not corporate) separation of Scotland from England & Wales.

 

·       Determination of efficient expenditure at a route level (rather than at a business-wide level).

 

·       Possible ring-fencing of individual routes on a profit & loss basis.

 

·       A possible move from narrowly defined outputs (eg. percent of trains on time) to more widely defined outcomes (eg. percent of customers satisfied).

 

·       A possible move from outcomes based solely on Network Rail’s performance to outcomes based on the wider industry, to encourage alignment between Network Rail and the train operators.

 

Next steps

 

There is obviously a lot of work to be done between now and early 2014, including work following on from the HLOS’s. Pipes & Wires will check back on this issue as ORR publishes various papers.

 

Aus & NZ – prescribing distribution charges

 

Introduction

 

Most of us accept that some restraint of overall distribution revenue (revenue cap) or the charges to individual classes of customers (weighted average price cap) is required. This article examines moves on both sides of the Tasman Sea to increasingly prescribe how different classes of distribution charges can be compiled.

 

Prescribing the charges

 

The mechanisms used to increasingly prescribe distribution charges are....

 

·       NZ - the proposed introduction of a new Part 12a to the Electricity Industry Participation Code (2010) to increasingly standardise distribution tariff structures that will inter alia reduce retailer re-pricing risk, prohibit distributors making retailers liable for customer insolvency, introducing a more prescriptive approach to negotiating Use of System Agreements (UoSA), and standardising prudential arrangements.

 

·       Aus - the proposed introduction of a new Chapter 5a to the National Electricity Rules to inter alia set out some guidelines for various classes of distribution charges (including cost-reflective costs for new connections, and spreading the cost of capacity upgrades).

 

The subtle differences

 

On the face of it, it would seem that both the Electricity Authority in NZ and the Australian Energy Regulator are tackling similar issues. However there are definitely some subtle differences between the 2 approaches, with the NZ approach shifting the balance of power more towards electricity retailers and the Australian approach really only emphasising what should be just good customer connection practice anyway.

 

Consulting on the proposed changes

 

Consultation in NZ closed on 21st June 2011, whilst consultation in Australia closes on 5th August 2011.

 

A bit of light reading…

 

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…

 

·       White Diamonds North.

 

·       Northwards March The Pylons.

 

·       Two Per Mile.

 

·       Live Lines (the old ESAA journal)

 

Conferences & training courses

 

The following conferences and training courses are planned...

 

·       Infrastructure: Investment & Regulation – Sydney, 21st October, 2011.

 

·       Fundamentals of the NZ electricity industry – Auckland, 26th – 27th October, 2011.

 

·       Fundamentals of the NZ electricity industry – Wellington, 9th – 10th November, 2011.

 

·       Fundamentals of the NZ electricity industry – Wellington, 8th – 9th May, 2012.

 

·       Fundamentals of the NZ electricity industry – Auckland, 22nd – 23rd May, 2012

 

House-keeping stuff

 

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Disclaimer

 

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.

 

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