04 Issue Utilities unbundled - EY - US · 2015-07-29 · Utilities unbundled – Issue 04 3...

Issue

04May 2008

Utilitiesunbundled

Fueling our future: big spending, big decisions

Analysis and comment on current issues in power and utilities

08 | Delivering America’s energy future

The massive challenge of building major new infrastructure

16 | Just the beginningGlobal private equity firm Carlyle on its new infrastructure fund

17 | Putting a figure on China’s energy needs

Big investment planned, grid opens up to overseas investors

ContentsIntroductionBig spending, big decisions

Utilities newsIndustry roundup

Deals roundup Reviewing worldwide transactions trends in 2007

Main featureDelivering America’s energy futureThe massive challenge of building a major new infrastructure

Regional reportsUS distribution network mapMapping US electricity grid territories

Just the beginningWe interview global private equity firm Carlyle on its new infrastructure fund

Putting a figure on China’s energy needsBig investment planned, grid opens up to overseas investors

Opportunities in Polish energy With its consolidation and liberalization program successfullycompleted, what’s next for this key east Europe market?

Industry trendsDebating the industry's futureGlobal Power & Utilities Symposium 2008

Are US utilities ‘powered up’ for IFRS?Dealing with the challenge of converting from US GAAP to IFRS

Texas may hold key to infrastructure investmentTax incentives could give companies superior returns

Coming soon: new ‘performance hub’ for European utilitiesUtilities are set to take a closer look at benchmarking

Surviving the perfect stormHow will utilities manage the huge risks facing capital projects?

CommentWho should pay for the vision of clean, reliable energy?

Ernst & Young contactsThe authors

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2 Utilities unbundled – Issue 04

Contents

Big spending, big decisions

With the US apparently moving away from its former

fossil-focused energy policy, Europe wrestling with

the issue of ownership unbundling and major

infrastructure investment needed across the board,

the energy community continues to face major

change and big decisions.

Comparing how energy markets are developing in the US and Europe – the interaction between market structures, investment needs, regulation and environmental policy – shows up some interesting contrasts.

3Utilities unbundled – Issue 04

Introduction

Introduction by Ben van Gils and Bob Ford.

Impact of regulation on investmentClearly there is a massive need for cash investment, particularly in energy infrastructure, in both the US and Europe. From a US point of view, the task of raising this money presents a considerable challenge (see page 9). The biggest uncertainty that could hold investment back lies in whether US regulators can be persuaded to allow energy businesses a fair return on this investment in future.

By contrast, it is not so much the issue of regulatory returns that could hold investment back in Europe, but the European Commission’s (EC) hard-line determination to push ahead with full market liberalization. Concerns about the impact of forcing companies to unbundle has led certain energy players to put investment on hold: why invest in your transmission system if you are about to be forced to sell it off?

Market reform: stop-start in the US, full speed ahead in EuropeMoves to liberalize energy markets in the US and Europe have achieved very different outcomes. The US pushed hard to liberalize energy through the 1990s, deregulated to some extent, and then ground to a halt for two reasons: the Enron scandal, which destroyed public trust in the concept of a highly liberalized, competitive market; and the lack of federal power to push consistent industry reform, state by state. There is no current indication of any further federal moves to liberalize: the focus is on making the best of the status quo.

The EC, on the other hand, is thoroughly convinced of the benefit of liberalization and has the power to enforce it. In pursuit of this vision, it has proved time and again that it means business and will use the courts and impose huge fines to get its way. Many of Europe’s big utilities are reluctantly submitting.

The price of a cleaner environmentIn Europe, regulation geared towards reducing emissions is currently more developed than in the US, providing more certainty for businesses to plan ahead (see ‘Comment’ article, page 28). It’s clear that Europe’s carbon cap and trade system will continue: the EU is set to reduce the amount of free allowances post-2012. It’s also widely believed that the US will ultimately introduce carbon cap and trade, probably in a federal target that individual states can decide how to deliver.

To date, there has also been comparatively more incentive for renewable and clean energy generation in Europe. The US is now making moves in a similar direction: initiatives like the new Renewables Portfolio Standards (RPS) aim to encourage investment in clean energy development and have, so far, been taken up by around half of the states in the country.

For both territories, the final big question is: what will the societal cost of clean and reliable fuel be? Production is bound to be more expensive, resulting in big energy price rises that could put business competitiveness and livelihoods at risk. It will be intriguing to see how policy-makers in the US and Europe try to resolve the issue.

Please call our authors if you want to discuss any topic raised here – you’ll find contact details on page 30-31.

Ben van GilsGlobal Power & Utilities Leader Ernst & Young Global Power & Utilities Center Düsseldorf, Germany

Bob FordAmericas Power & Utilities Sector Leader Ernst & Young Americas Power & Utilities Center Washington DC, US

New Americas Power & Utilities CenterErnst & Young continues to invest to help utilities clients meet their goals and compete more effectively. In response to the growing challenges facing energy companies in the US, we opened our new Americas Power & Utilities Center in Washington in January 2008. For more information, please contact Amy Dorcy on tel + 1 202 327 5784 or email: [email protected].


RWE AG has agreed to buy a 50% stake in liquefied natural gas (LNG) provider Excelerate Energy for US$500 million. The German utility stated that it will benefit from Excelerate Energy’s onboard regasification technology: regasifying LNG on board eliminates the need for expensive LNG terminal infrastructure.

Following a severe shortage in electricity due to rapid economic growth, China has announced the building of its first inland nuclear power station in the province of Hubei. The nation seeks to have 40 GW of nuclear capacity by 2020 – equivalent to 4% of the total generation mix.

In a move to increase security of supply and reduce carbon emissions, the UK government has given the green light to a

new generation of nuclear power stations. The building program could see new facilities in operation well before 2020. Both the announcement and rumors that the government might sell its 35% stake in nuclear operator British Energy have sparked keen interest from European energy giants EdF, RWE,E.ON, Centrica, Vattenfall and Iberdrola to buy into the UK’s nuclear revival.

Europe is seeking alternative gas supplies from Central Asia. The EU-lobbied Nabucco pipeline will cost between €5 billion to €7 billion, crossing Azerbaijan, Turkey, Bulgaria, Romania, Hungary and Austria. Current shareholders include OMV, MOL, Transgaz, Bulgargaz Holding, BOTAS and RWE.

In the US, a major initiative to reduce greenhouse gas emissions from power generation suffered a serious setback after the Department of Energy (DoE) backed out of the FutureGen project. The DoE is now looking to invest in several carbon capture and sequestration (CCS) projects at commercial integrated gasification combined cycle (IGCC) plants.

Utilities news

Utilities newsThe environmental challenge

Market forcesSecurity of supply

TRUenergy, the Australian subsidiary of Hong Kong based electricity utility CLP, has partnered with Melbourne-based Solar Systems to develop the world's largest photovoltaic solar power station. TRUenergy and Solar Systems will develop a 2 MW heliostat concentrated photovoltaic pilot plant, subsequently investing up to A$285 million to build the remaining stages of the 154 MW project in northern Victoria, Australia. The Australian and Victorian governments have also committed approximately A$125 million in funding for the project, which will be capable of powering 45,000 homes. Work will begin in 2009 and is scheduled for completion in 2013.

The significant size and growth prospects of Spain’s utilities market continue to attract attention from other European players. The acquisition of Endesa by Enel and Acciona has provided a template for targeting other incumbents in the Spanish utility sector, with EdF or, in a friendly deal, Gas Natural now rumored to be investigating a bid for Iberdrola.

Scottish & Southern Energy (SSE) has completed its acquisition of the Dublin-based wind power company Airtricity for €1,455 million. SSE is now reportedly the largest wind farm operator in the UK and Ireland.

UK energy business Centrica has announced it is taking a minority stake in Ceres Power Holdings plc, a business developing combined heat and power (CHP) systems

based on solid-oxide fuel cell technology. Approximately 1.5 million domestic central heating boilers are replaced each year in the UK and it has been suggested that residential CHP could take 30% of this market by 2015, reducing both household energy bills and carbon emissions.

The European Commission has proposed a new energy and climate package with a 20% renewable energy target by 2020. Member States will have to establish their own national support systems to meet the target. Emission certificates for power companies, tradable under the EU Emissions Trading Scheme (ETS), are likely to be fully auctioned from 2013.


Utilities news

Source for all information: Factiva; Ernst & Young

Regulatory forces

Profitability of revenues

The challenges facing the utilities sector have driven UK energy market regulator Ofgem to announce a review of the UK’s gas and electricity network regulatory regime. The review will investigate whether the current framework can deliver reliable energy at reasonable prices.

Deregulation in Japan will be suspended for another five years. Full competition was planned to be effective in 2009. Now a Japanese government panel has approved the suspension, arguing that there have been fewer entrants to retail markets than expected. Before full retail competition will be considered, other measures including enhanced wholesale electricity trading

Regulated electricity rates in Hong Kong will be subject to the emission reductions the utilities achieve. China Light & Power and Hong Kong Electric have agreed to a regime whereby the allowed rate of return is based on pollution. The system includes a bonus if the utilities achieve better-than-target reductions by using renewable energies.

The majority of the UK’s integrated electricity suppliers have confirmed price rises for domestic gas and electricity customers. The price hikes have brought the issue of fuel poverty back into the spotlight: campaigners have taken the UK government to the High Court over its failure to provide adequate measures for those who suffer from high energy bills.

The second trading period under the European ETS will have significant impacts on the profitability of European utilities operating coal-fired power stations. Sweden’s Vattenfall is expecting an aftertax burden of €500 million per year until 2012, resulting from an annual shortage of 30 million emission allowances.

State Grid of China reported 84% growth on its 2006 earnings before tax. China’s largest mainland power distributor said pre-tax earnings surged to US$3.5 billion due to the continued growth of the nation’s economy. Installed capacity in Asia’s power house increased to 713 GW, a 14% growth over last year’s figures. Total investments in transmission in China could reach US$250 billion between 2006 and 2010.

and rate reviews for transmission lines should be taken, the panel proposed.

West Virginia regulators have granted authority for Appalachian Power, a subsidiary of American Electric Power (AEP), to build a US$2.2 billion, 629 MW IGCC electric generating plant in West Virginia. This is the first of two AEP-proposed IGCC plants for use as new base-load generation in AEP's seven-state eastern portion of its service area. Construction will begin after approvals are received from Virginia regulators and the West Virginia Department of Environmental Protection. From the time construction begins, AEP estimates it will require approximately 48 to 54 months to complete the IGCC unit.

Amid European proposals to further unbundle power and gas companies, German power and utilities company E.ON has announced it will sell its power grid assets to settle another investigation into the lack of competition in German energy markets launched by the European cartel authorities. Under the agreement, E.ON will also sell 4,800 GW of generation capacity.

In France, the proposed €75 billion merger of Gaz de France (GdF) and Suez has been delayed by work council disagreements. GdF’s European unions are demanding a bigger share in the combined entities’ council before they will give approval.


Deals roundup

Deals roundup 2007 In 2007, utilities completed an unprecedented volume of transactions despite the credit crunch midway

through the year. Renewables also took a big leap forward. Report by Joseph Fontana.

Highlights • Bumper year for M&A but slow down in third quarter • Big push on renewables (in the US, driven by Renewables Portfolio Standards) • Consolidation in renewables, investors broaden beyond venture capital

Table 1: Completed deals in 2007

Half 1 Half 2

Q1 Q2 Q1 Q2

Volume

Average value(million US$)

Volume


Volume


Volume


Utilities —> utilities 19 366 20 606 6 415 22 407

Renewables —> renewables 7 210 3 642 4 86 8 49

Utilities —> renewables 1 n/a 2 n/a 3 72 5 330

PE,INF* —> utilities n/a n/a 3 614 1 355 10 774

PE,INF* —> renewables n/a n/a 3 1 3 44 3 112

The big picture – a year in review

Looking at the numbers, 2007 was a good year for M&A globally, with unprecedented volumes of utilities transactions. The tighter credit conditions in many markets in the second half of the year didn’t slow down the number of completed deals (Half 1: 58 v Half 2: 65, see table 1). Announced deals were also up in the second half of the year (see table 2), so there is no indication of a slowdown in deals yet: figures for 2008 might look very different.

Another significant trend was the growing involvement of utilities in renewable energies. Utilities are waking up to the potential of these companies, and buying stakes or whole companies in the renewables sector. While there were just three of these transactions in the first half of 2007, this jumped to eight in the second half. More significantly, the average deal value for utilities buying renewables increased dramatically to US$330 million in Q4. Last but not least, the massive infrastructure investments needed to maintain supply security and system adequacy have generated transactions as utilities are putting assets up for sale in order to raise money to invest in core businesses.

Movers and shakers

Out of the more than 120 transactions in 2007 that we focused on, more than 50% were utilities buying utilities. On average, these transactions had a value of US$449 million.

Perhaps the most surprising development is the sustained involvement of financial buyers in utilities M&A markets. To a large extent, this involves private equity (PE) and infrastructure funds buying infrastructure assets for their steady returns and portfolio-balancing characteristics. In the last three months of 2007, 10 deals were completed with an average value of US$774 million.

In the renewables sector, we have seen two different types of consolidation. While smaller renewables players tended to buy peers or smaller competitors, utilities purchased larger renewables portfolios after production had begun. Apart from venture capital, these markets have seen both strategic and financial investors that are particularly keen on the future growth prospects of these more sustainable technologies.

Source: Datamonitor; analysis: Ernst & Young*Private equity and infrastructure funds


Deals roundup

In the second half of 2007, we began to see the effect of the

reduction of cheap money – which has hit both financial funds

and utilities.

Deals commentary

Report by Joseph Fontana.

Table 2: Announced deals in 2007Sector coverage Energy and utilities combined Utilities

Jan-Jun 07 Jul-Dec 07 Jan-Jun 07 Jul-Dec 07Acquisition 568 1113 300 577

Merger 15 31 3 13

Private equity 38 86 16 31

Private placement 149 207 30 50

Public offering 92 167 27 57

Venture finance 11 26 9 21

Partnership 283 283 139 139

A driving force for those selling assets is the urgent need to invest in infrastructure – without raising their debt levels. Utilities are examining what may no longer be core to their business and selling assets to raise money for projected capital expenditure (capex) requirements within their core businesses. For example, PNM Resources announced the sale of its gas business for US$600 million, in part to raise capital to invest in its electric business; and Consolidated Edison’s US$1.5 billion proceeds from the sale of ConEdison Development Company will be partly reinvested in its distribution business. Sales are also being driven by the relatively high values these assets are gathering.

Who is buying the assets?

Infrastructure funds are a big player. Four years ago, there was no infrastructure fund ownership of utilities in the US, but conditions right now appeal to them. Infrastructure funds will not avoid utilities that require large ongoing capital investments – as long as they perceive the regulatory process as fair and transparent. Macquarie’s acquisition of Duquesne Power and Light, and its announced intention to buy Puget Energy, are two recent examples.

While infrastructure funds are primarily buying US electric and gas assets at present, they could decide to try to replicate their success in Europe or elsewhere. Should ownership unbundling go ahead in the EU, prime targets for the funds would be the highly regulated transmission assets.

Developments in renewables and regulationIn the US, 26 states and the District of Columbia have put standards in place regarding the percentage of power that utilities must obtain from renewable resources - the Renewables Portfolio Standards (RPS)1. While varying in each state by percentage requirements, implementation date and even what constitutes renewable power2, at a minimum the standards require utilities to either acquire or self-supply renewable power. Interestingly, the percentage of power supplied by renewable resources in the US was approximately 10% in 2006. However, hydro resources represented almost 8% of the total renewable power produced and in many of the RPS states, hydro generation does not qualify as a renewable resource. As a result, some states will still have to build a significant amount of

new renewable generation to achieve their targets. Several industry observers believe that achieving the target will be made more difficult by the overall shortages in raw materials caused by a worldwide buildout of all types of new generation. As long as a shortfall exists, investment in renewable generation will continue to grow as developers and acquirers take advantage of a market out of equilibrium.

While RPS has created the need, only a few utilities have made a major investment in renewable power to date. FPL has been a leader for several years in nonregulated generation, owning wind farms in 16 states as well as approximately 150 MWs of installed solar generation. Utilities such as AES and Mid-American have also made significant wind investments in recent years. Some of the larger players in wind are non-US based utilities, including Iberdrola, Energias de Portugal (EDP) and E.ON.

Possibly the most interesting aspect of RPS is the opportunity for transmission investment – there simply isn’t enough for all the assets that are being planned. The need is amplified by the significant transmission investment required to expand the US grid to meet the demands of a dynamic, competitive wholesale marketplace. The Federal Energy Regulatory Commission’s (FERC) effort to entice transmission investment, as well as the incentives certain states are offering to have transmission built to support renewable power generation, may mean that utilities that invest in transmission will be RPS’s biggest beneficiary.

Source: Datamonitor

1 Four other states have voluntary regimes2 Standards range from 4% for load-serving entities in

Massachusetts to achieve by 2009, to 25% for load-serving entities in Illinois, Minnesota and Oregon by 2025


Main feature

Delivering America’s energy futureReport by Bob Ford, Joseph Fontana and Patrick Cass.


Main feature

“ There’s an old joke that only two national energy policies have ever existed – complacency

and panic. The US has experienced a period of relatively easy access to affordable energy,

and you could say we became complacent. Now that we’re fully awake to the major

challenge of delivering affordable, available, sustainable energy for the future, we don’t

need to panic. The issues are complex, and the risks and opportunities are enormous, but

they can and must be dealt with in a holistic, structured way.” Bob Ford

Replacing North America’s aging energy generation plants and networks,

developing technology for cleaner fuel, introducing renewables: the list of

urgent new infrastructure demands is endless – and expensive. What key

challenges do US utilities face in delivering a secure energy future?

The US power and gas industry is – in common with the rest of the world – witnessing the most revolutionary period of change since the first utility systems were built. The era of easily available, affordable energy is rapidly ending and our society is realizing that our energy infrastructure is severely inadequate to supply the energy demands of the future. The major issue facing the sector today is how to fund and deliver this new climate-friendly infrastructure which is currently estimated to cost almost US$2 trillion1 between now and 2030.

To be successful, the energy stakeholders in the US must collaborate to bring affordable power to our citizens. A successful end result will require creative financing structures and techniques; tax incentives; enabling legislation for new nuclear facilities, renewable and environmental requirements; and new grid technologies to lower and shape the system load, improve reliability and deliver more of the power produced.

In recent years, US utilities have deferred major infrastructure investments because many of them were locked into multi-year tariff freezes and were working off so-called excess capacity. Some companies cut back discretionary capital spending, choosing to focus resources instead on reducing debt and restoring their financial strength. However, the years since 2005 have seen a period of accelerated investment in capex. Influential factors encouraging higher investment in infrastructure spending have included policy concerns about energy reliability and diversity of source; the introduction of tighter environmental rules; and of course the heavy strain of an aging generation, transmission and distribution system.

This leaves utility CEOs facing major questions which affect the long term, but need answers today:

Where is the money going to come from for the increased infrastructure – and are the • nation’s utilities balance sheets strong enough to finance these massive investments?

How can management teams be sure they are making the right investment decisions? •

What are the financial implications – especially in terms of impact on revenues? •

How are they to fill the critical people skills gaps facing the industry? •

1 Source: IEA, World Energy Outlook 2006


Main feature

The question of which investments will prove most attractive really depends on the individual buyer’s risk and return profile. An infrastructure fund, for example, will be drawn to buy rate-regulated utilities, and will probably prefer to invest in states with a track record of consistent, predictable and transparent regulation5. But whilst infrastructure funds are likely to be content with the dividend yield that regulated utilities will generate, PE buyers may seek to leverage any such investment to generate greater returns, or exit. Alternatively, PE buyers may avoid regulated utilities altogether in favor of buying generation, which provides the opportunity – particularly in the country’s liquid markets6 – to earn hefty returns. Others (such as ITC Holdings) may be attracted to invest in transmission because of the FERC incentives available. There could also be potential for sovereign wealth funds to invest in infrastructure, although they will face close scrutiny and are likely to be disappointed if the asset they want to buy is considered strategic.

The entry of these alternative buyers has created an opportunity for utilities to sell those businesses that compete for capital with their core, strategic businesses. What we are also therefore likely to see is an increase in divestments to raise the cash for vital new infrastructure spending7. Some smaller utilities may be forced to merge or combine to ensure adequate critical mass so that they can afford the necessary investments.

Can you be sure of a return?One fundamental thing all utility investors want to know is: “will the regulator allow us to recover the cost of our investments in future years?” Recent disappointing rate cases might give some cause for concern on this front: for example, PNM Resources has just received a very disappointing decision which has slashed its permitted return on equity. This has happened before it has even started building new infrastructure. When it does begin building in earnest, it will mean further pressure on rates. Regulatory battles like this can be demoralizing and can prompt companies to

Sources of finance and the effect on revenuesSo where will the capital come from to fund this big infrastructure buildout, and what are the barriers to ensuring recovery of costs?

Where’s the money?Despite the current US credit crunch, the general consensus is that capital is still (and will continue to be) available. Well-prepared utilities with strong balance sheets shouldn’t face major problems in finding banks to lend them money, or in raising cash through other traditional routes like mortgage bonds and equity offerings. However, many companies that are less financially fit will experience a more challenging time raising capital and can expect higher financing costs.

In addition, there is plenty of room for funding from newer sources. US-based data reveals, for example, that in 2007 there was US$302 billion of PE inflow to funds2; hedge funds raised US$194.5 billion3; and in the two years from 2006-07, US infrastructure funds rose by US$150 billion4. A good proportion of this money could make its way into the utilities industry, which is highly attractive due to its low risks and stable returns.

Developing US energy infrastructure

The major issue facing the US energy sector today is how to fund and deliver major new infrastructure, while the industry is influenced – in conflicting directions – by key industry drivers such as sourcing competitive supplies, environmental forces, regulatory forces, market forces and profitable revenues.

2 Source: Dow Jones Private Equity Analyst newsletter, January 2008

3 Source: Hedge Fund Research report, January 2008

4 Source: Crédit Suisse, ExNet M&A conference, January 2008

5 E.g., this was the reasoning behind Macquarie’s investment in Puget Energy in Washington DC

6 E.g., PJM, NY ISO, ERCOT, CAISO and NE-ISO

7 E.g., PNM Resources recently announced plans to sell off its gas business to focus on electricity; and ConEd announced the sale of its unregulated generation to focus on its distribution business

*Energy Policy Act of 2005

Source: Ernst & Young

Regulatory forces and incentives

Infrastructure funding

Market forces

Competitive supplies

National supply security

Cost/availabilityof primary fuels

EP Act* Retail energy cost

Consolidation of new investors

Rate of return

National environmental performance

Environmental change

Profitable revenues


Brazil

Developing countries = 57% of world total

Transition economies = 5% of world total

OECD = 38% of world total

0 500 1,000 1,500 2,000 2,500 3,000 3,500

Middle EastOther Latin America

AfricaRest of developing Asia

IndiaChina

Transition economiesOECD PacificOECD Europe

Power generation

billion dollars (2005)

Transmission Distribution

OECD North America

Main feature

“Infrastructure funds are here to

stay, and are already acquiring

hard infrastructure assets around

the globe. PE houses and venture

capitalists are also prepared to

invest their millions betting on the

future of utilities, and new funds

looking to invest capital include

the sovereign wealth funds.”

Joseph Fontana

think twice before they invest. It’s no wonder that infrastructure funds seek out opportunities in states where they trust they will be allowed to earn steady, regulated returns – as in Macquarie’s recent proposed acquisition of Puget Energy.

However, even if the regulator gives investors serious reasons to pause, realistically at some point further delay is impossible and the money must be spent: otherwise, the lights go off. Regulators realize this too. Although they may act aggressively on pricing in favor of customers, they know it is ultimately in the best interest of the consumer to have consistent, fair regulation, because inconsistency adds delay, which in turn impacts both investment and supply reliability. It will be interesting to see whether the reliability of power increases in future in states where the regulators prove most consistent in their approach to pricing.

Time to deal with massive skills shortage

If one key question concerns sources of finance, the other big issue is finding enough people to deliver the program. It will take a huge, skilled workforce to build the new infrastructure we need now, and operate and maintain it into the future. While there are plenty of options for raising money, the answer to the people issue is more complex.

The size of the funding challenge: infrastructure investment to 2030, according to IEA World Energy Outlook 2006

8 Estimate from Paul Bowers, President of Southern Company Generation, to the Senate Committee on Energy and Natural Resources. Reported by Electric Power Daily 7 November 2007

Forecast cumulative (2005-2030) power sector investment by region

A pervasive talent shortage has been quietly growing. It began with the need to control operating costs, and was exacerbated by the fact that the last major buildout of the US system ended in the 1980s. This skills shortage is now a serious threat. For example, around half of the electricity utility workforce could become eligible for retirement within a decade8 – and businesses are not even attracting enough people to replace these retirees, let alone account for expected growth. The shortage is across the board: from nuclear engineers to experienced plant operators, from geophysicists and geologists to construction project managers, from senior management teams to field workers.

We may even have reached the point where future energy supplies – including the type of infrastructure we build – could be dictated by the sheer unavailability of skills. If, for example, there is a 15-year time lag to get sufficient numbers of people through the necessary nuclear engineering training, utilities may well decide not to build nuclear, but meet demand through other routes.

The obvious result is that attracting talent will become increasingly costly and competitive, and that training expenses will necessarily rise. The more proactive companies are tackling the problem at root level, developing relationships with high schools to boost interest in the careers they can offer and to attract people into industry training programs. Power and utility companies are also reaching out to energy service companies and outsourcers for a greater proportion of their generation and T&D (transmission and distribution) construction and maintenance, and this trend is widely expected to accelerate as the workforce challenges grow more severe.

Supply chain feels the pinch Another influential factor is the question of whether critical infrastructure components are actually available to buy. As is evident from the IEA forecast (see graph above), the US is competing with the rest of the world for the same resources.


Main feature

In the run up to November’s election, the key political parties have all said they believe in some form of carbon control. If the Democrats win, broadly speaking, most Americans believe that there will probably be a quicker response and attempt to instigate more stringent regulations than if the Republicans win. We will have to wait until after America's November election to see what the concrete effects on the industry as a whole, and investment in particular, will be.

The cost of carbonState by state, the current picture is patchy. One major move is the introduction of RPS, which is currently in place in 26 states plus the District of Columbia9, and requires utilities to supply a certain (in some cases sizeable) percentage of power from renewable sources. Some tax credits and other incentives are available to help create this new renewable supply, but the ultimate effect has to be an increase in the cost of power, simply because renewable power sources like wind are more expensive on a kWh basis than coal or a combined cycle plant.

We are still guessing about the price of carbon, and waiting to see what the federal government will do about carbon regulations. Ten northeastern and mid-Atlantic states plan to implement the Regional Greenhouse Gas Initiative, or RGGI. Effective from next year, this will put a cap and trade program in place around carbon, with customers ultimately bearing the cost. The real cost of carbon will become evident to customers for the first time. How they react, and whether the system is effective or not, will depend on how the system is put into action – and at what level RGGI sets the cap. California is set to implement a similar program.

Societal impactsThe big issues for the politicians are what tolerance is there amongst consumers (i.e., voters) as a whole to soak up price increases, and what will the societal effects be? After all, there is more at stake than a clean environment. In the Midwest, whose manufacturers need to be competitive on a worldwide basis, industrial electricity customers are currently paying around five cents per kWh for their electricity. What happens to those manufacturers if the price of carbon pushes electricity up and suddenly the economics of manufacturing in the Midwest don’t make sense any more? As to the effects on residential customers, figures from the Lieberman-Warner Climate Change Bill estimate the cost of carbon could reach US$54 to US$64 per metric tonne in 2020, rising to US$227 to US$271 in 2030. This could dramatically drive up the cost of residential power: there is potential for political mayhem.

Heavy worldwide demand is putting massive pressure on the whole supply chain, resulting in big price rises for raw materials like uranium, and long waiting lists for manufactured components like turbines. At present, for example, there is only one heavy metal forger in the world (located in Japan) which can build the necessary steel pressure vessels for nuclear plants. How are they to cope with demand from the US, let alone the rest of the world? Of course, prices will rise.

Fuelled by massive demand from developing economies like China and India, prices for vital commodities like steel and cement have also risen – it’s the same dynamic which is driving the price of oil higher. This factor also, inevitably, pushes up the price of infrastructure building programs. It is likely that the US$1.6 trillion figure for infrastructure building will prove an underestimate: next year’s IEA schedule of forecast investment for the coming decade could be very much higher due to these skyrocketing raw material costs.

What can we expect in future? Realistically, it is possible that we could see some demand destruction, either because of rising prices or slowing economies, or both – but if so, this is likely to be a temporary dip rather than an extended trend. Long term, the assumption is that world economies will continue to grow, and growing demand will keep prices up.

Environmental influences: the real costs of being cleanThe current uncertainty about forthcoming environmental regulation on carbon emissions puts power and utility companies on shifting ground in terms of business planning and investment decision-making.

“ Just as we saw with LNG a few years ago, everyone now seems to regard nuclear power as their supply backstop. Everyone is thinking about resources like uranium and saying ‘there is just enough for me’ – but every country is matching itself against the same resources. In planning this new infrastructure, we must not fall into that trap.” Joseph Fontana

9 Four other states have voluntary regimes


Main feature

Standard & Poor's (S&P) recently took the view10 that the market could absorb the cost of carbon if it is done gradually, but that it would be disastrous for utilities if it is instigated aggressively and too quickly. We have to hope that this warning is heeded and that the approach taken by those responsible will be prudent, rather than zealous.

Clean coal is not deadFor two years, the proposed US$1.8 billion FutureGen project, a single plant to test various coal types with gasification technology and permanent carbon capture and storage (CCS), was favored by the Department of Energy (DoE). Recently, amid concerns over massively escalating costs, the DoE has reconfigured the project: the money will now be split into smaller packets to help utilities with the cost of CCS at plants still to be built. As this change of plan will delay commercialization of CCS technology by four years, investors might think this implies that the DoE’s belief in coal and CCS has waned. So is there a future for investing in clean coal? The answer is: probably.

Private enterprises are still investing in carbon sequestration11. Without up-front government funding, clean coal could be further off on the horizon, but there is no reason to believe the technology won’t happen.

In the meantime, Congress is now putting through a bill which will ban construction of any coal plants unless carbon controls are in place. However, there is a major energy conundrum here. If you don’t want coal, you need nuclear to meet demand, and there is also considerable debate about the desirability of nuclear.

Market forces at work? Looking at the market as a whole, it’s clear that the wave of consolidations which some predicted would occur over the past five years hasn’t materialized. That’s not wholly surprising, given that the regulators have shown a determined and aggressive tendency to refuse any transactions which they felt did not provide sufficient benefits to customers.

However, just because this may have put merger plans on hold for some companies, it doesn’t mean consolidation will not proceed in future. And while this may affect certain companies’ freedom to invest, consolidation is only one avenue to raising cash. There are still many alternatives to explore: aspiring investors will also be considering selling off noncore assets to raise cash; going to the debt markets; raising structured finance; or entering into joint ventures with alternative capital providers.

10 The Race for Green: How Renewable Portfolio Standards Could Affect US Utility Credit Quality, Standard & Poor’s, 10 March 2008

11 Including LS Power, which has just initiated a research study on the subject with the University of Texas at Austin

“ We all like the idea of clean power, but not at the price of putting businesses out of action or people out of

work. We have to hope that those in charge will introduce any emission regulation slowly and set prices

prudently, to allow the market time to absorb the change.” Bob Ford


Main feature

“This initiative will require creative financing structures and techniques,

tax incentives, legislation for new nuclear facilities, renewable and

environmental requirements, and new grid technologies.” Patrick Cass

A positive outlook – but utilities need strong controls The US urgently needs this growth in infrastructure to secure its energy future, and well-delineated projects with a clear business case should have access to adequate funding. However, there are challenges: a shortage of skilled people; uncertainty about the way environmental regulation will affect the future; and of course, regulatory barriers to overcome to get a solid return on your investment.

Investors will be wary of repeating past investment cycles, in which some of the companies with the most aggressive spending programs suffered an erosion in financial condition. S&P sees some risk on the basis of the industry’s previous experience in buildouts12: it is possible that a track record of rate freezes or prudency disallowances could make some utilities or states less attractive for investment than others. Investors will be carrying out careful due diligence to clarify whether there is a reasonable chance of future recovery of costs.

Utilities themselves will need to manage the process meticulously to avoid the risk of prudency write-offs, putting strict controls in place to manage the buildout and ensuring they have the regulator’s sign-off at each step of the development process.

Taking action to secure future energy needs

Stakeholder goal: working together to provide clean reliable energy – resulting in the lowest long-run revenue requirement from the nation’s energy customers.

Recommended stakeholder actions

1. Regulators • Set reasonable renewable

requirements/targets • Allow construction work in progress

(CWIP) in rate base and timely recovery of prudently incurred costs

• Encourage grid investments to enable load shaving/shaping and lower line losses

2. Legislators • Create tax incentives (credits, faster

depreciation etc.) to help fund the needed investments

• Instigate reasonable air quality phase-in periods that achieve the necessary science goals, while not driving the industry to make imprudent decisions

• Resolve the spent nuclear fuel issue, either through secure permanent storage or reprocessing

• Establish national goals and frameworks for the patchwork of stakeholders to seamlessly work together towards the common goal

3. Wall Street • Create guidelines for allocation of

financing capital, cost targets, balance sheet ratios, etc.

• Provide creative structures/instruments to open up new sources of capital

4. Power and utility companies • Develop robust controls for managing

all capex project risks • Conduct proactive prudence activities

for Wall Street and regulators, in return for improved regulatory certainty and lower financing costs

• Create buildout plans to meet stakeholder needs in a thoughtful, cost-effective manner

12 Source: Credit Perspective Regulatory Risk Remains for US Utilities, Standard & Poor’s, 24 March 2008


Regional reports

US distribution network map

AEP

PCG

CNP

AEP

AEP

ETR

ETR

ETR

ETR

ETR

OTTR

OTTR

AEP

AEP

AEP

AEP

AYE

AYE

AYE

AYEAEP

NST

PEG

PPL

EXC

ED

GZM.UN

CV

ED

POM

DPL

NWEC

NWEC

WR

NWEC MDU

MDU

MDU

MDU

TE

PNM

AEP

AEP

CMSDTE

EAS

EAS

EASWEC

WEC

POR

FPL

FE

FE

FE

FE

PSD

DUK

PNW

DUK

DUK

EXC

AEE

AEE

LNT

LNT LNT

TXU TXU

CNL

XEL

XEL

XEL

XEL XEL

XEL

XELXEL

ILA ILAGXP

ILADUK

D

D

PGN

PGN

PGN

SO

EON

EON

SO

SO

SO

AEP

AEPOGE

EIX

MEHC

MEHC

MEHCIDA

IDA

MEHC

AVAAVA

MEHC

MEHC

SRP

SRE

NGG

NGG

NGG

NU

NU

HE

AEP = AEP

AYE = Allegheny Energy

AEE = Ameren

AVA = Avista

CNP = CenterPoint Energy CNL = Cleco CMS = CMS Energy

ED = Consolidated Edison

CV = Central Vermont Pub Serv Corp D = Dominion Resources

DTE = DTE Energy DUK = Duke Energy

DPL = DPL Inc.

EIX = Edison International

EAS = Energy East Corporation

ETR = Entergy EON = E.ON*

LNT = Alliant Energy ILA = Aquila

EXC = Exelon FE = First Energy Corp FPL = FPL Group

GZM.UN = Gaz Métro* GXP = Great Plains Energy

HE = Hawaiian Electric IDA = IDACORP

MEHC = Mid American Energy Holdings** MDU = MDU Resources Group Inc

NGG = National Grid

NU = North East Utilities NWEC = NorthWestern Corp

NST = NSTAR

OGE = OGE Energy Corp OTTR = Otter Tail Power Co

TXU = Energy Future Holdings Corp**

PGN = Progress Energy

POM = PEPCO

PCG = PG&E Corporation

POR = Portland General Electric

PNW = Pinnacle West PNM = PNM Resources

PPL = PPL

PEG = PSEG

PSD = Puget Energy

SRE = Sempra Energy SRP = Sierra Pacific Resources

SO = Southern Company

TE = TECO Energy

WEC = Wisconsin Energy Corp WR = Westar XEL = Xcel

Key

Investor-owned utilities serving the US, May 2008 This map shows the electric service territories of investor-owned utilities in the US, by holding company. Service territory is defined by the ownership of the electric distribution network. Federal, state and community-owned utilities are not shown. Companies are identified using their NYSE ticker symbol.

For more detailed information on the operation of utilities in the region, or for larger copies of this map, contact Theresa Hagemeister on + 49 211 9352 10628, or email: [email protected]. Similar maps are available for Europe and Asia Pacific.


* non-US Stock Exchange

** formerly listed, currently private

Alaska

Hawaii


Regional reports

Government privatizations, new build, and public-private partnerships have pushed up demand for the private

sector to fund public infrastructure. At the end of 2007, global private equity firm The Carlyle Group completed

a US$1.2 billion fund to invest primarily in transportation and water infrastructure in the US and Canada.

Joseph Fontana interviews Carlyle’s Bryan Lin on the new fund and future prospects.

Q: Why does Carlyle want to invest in infrastructure and utilities?

A: Institutional investors, and particularly pension funds, are attracted to investing in assets that offer long-term, stable returns. Our new fund reflects this demand. Infrastructure is highly attractive because of the long lifetime and low risk profile of the assets. Utilities are attractive because of the regulated nature of much of the business, which makes for predictable returns. Utilities also tend to provide services which are publicly essential – they’re always needed, no matter how the economy performs.

Q: Will this fund only invest in North America?

A: That’s our primary focus, but we have the option to use up to 30% of the fund to buy elsewhere – most likely in Western Europe. This is just our first infrastructure fund: I’m sure that for future funds our sector and regional focus will be much broader, depending on where we see the strongest opportunities.

Q: Do you worry about pressure from regulators?

A: In dealing with these highly regulated businesses, your relationship with the regulator is a big part of making a successful investment. Regulators can

Just the beginning

be very demanding and impose stringent conditions – on anything from quality of service to future required investment. But those demands are far from being a problem: after all we’re here to grow the businesses we buy. If that entails committing to capex investment, we will do it – it’s part of our strength. In terms of the regulator’s attitude to our returns, of course they are there to protect the consumers and they might ask for a rate freeze or some other substantial concession. You just have to be prepared, do your homework up front before you take the investment on, and establish good relationships.

Q: What kind of returns do your investors (LPs) consider attractive?

A: I don’t think infrastructure fund LPs’ expectations are much different from any other investor. Our proposition might offer somewhat lower returns than a traditional LBO type of transaction, but it’s also lower risk – so on a risk-adjusted basis, investors are no worse off. As an asset class, infrastructure provides good portfolio diversification.

Q: How involved do you get in running the businesses you buy?

A: We don’t get involved in day-to-day operations. Typically, on new acquisitions we’ll run an initial exercise working with the management to analyze company strengths and weaknesses, identify opportunities and map out the business strategy. We then provide whatever support management needs to grow the business, monitoring their performance against the plan, and making changes as necessary along the way.

Q: What success do you think infrastructure funds will have in this space?

A: I certainly think there will be more participation and investment in utilities from infrastructure funds in the next

Bryan D. LinPrincipal The Carlyle Group

Bryan is a principal at The Carlyle Group, a global private equity firm. Bryan focuses on infrastructure investment opportunities. He is also a member of the board of directors of Synagro Technologies, Inc., a leading wastewater residuals management company acquired by Carlyle in April 2007. Bryan is based in New York City.

three to five years. To date, in the power and energy sector financial players are already very active in aspects like generation and gas. On the regulated utilities side, we haven’t yet seen as much infrastructure fund activity here in North America, but I think that may well change. It will be interesting to see how the investments that have been made in the regulated sector actually perform, once the funds exit. The overall attitude of the regulators will also be key: there is a limited amount of publicly available funding to make the necessary investments which the industry cannot afford to further postpone, so going forward we believe they’ll view our presence in the sector as helpful.


Source: Business Monitor International (BMI)

Power generation – China 20070.6%2%

19.7%

3.8%4.2% 69.7%Coal

OilGasHydroNuclearNon-hydro renewables

Source: China’s electric power industry market analysis and forecast report 2006

Power generation – China 202026.3%2.1%

2.1%

69.5%HydroThermal(coal, oil and gas)NuclearWind

Regional reports

Despite the fact that it is the largest energy producer in the world1, China is still largely dependent on imports to fuel its power stations. The country boasts substantial volumes of domestic coal – the dominant fuel type in power generation at present – but its demand for natural gas and oil continues to rise faster than its domestic production.

In the face of soaring energy demand, Beijing is aggressively diversifying its overseas energy resources, moving for example into West Africa, Venezuela and the former Soviet states of Uzbekistan and Kazakhstan. Meanwhile, on the domestic front, its current five-year plan for energy development – covering the period 2006 to 2010 – calls for an increase in the share of gas and other cleaner technologies in the country’s energy mix and major investment in the grid.

Grid opens up to foreign investmentChina’s electricity industry is mainly publicly owned and controlled at the level of local and central government, although there are signs that liberalization is beginning. The generation sector is currently dominated by five state-owned holding companies which manage 80% of China’s generating capacity.

Electricity transmission and distribution is run by two state-owned companies at present. Reports in the Chinese media indicate that infrastructure deficiencies have cost the power-generation sector US$650 million in losses since 20062 and impacted on the reforms in the sector since 2002. The State Grid Corporation of China will therefore be spending RMB1,000 billion (US$142.4 billion) over the next five years on upgrades to the country’s electricity transmission network.

At the same time, China will be opening up its electricity sector to foreign investors. However, as power is regarded as a matter of national economic security, the National Development and Reform Commission (NDRC) will limit foreign players’ involvement to power grid construction and operation, with the mainland domestic companies retaining the controlling interest. Chinese officials have stated their intention of enabling plants to sell power to the grid at market-determined rates.

Investing in renewablesChina intends to more than double its reliance on renewable energy by 2020 compared with 2005. The country already has a substantial hydro-power business, but there is enormous potential for the development of further hydro resources, with Business Monitor International predicting that by 2012 hydro-power could provide around 25.1% of the country’s total generation.

There will also be considerable emphasis on developing wind and solar power. By 2010, the intention is to build about 30 large wind-power plants and 5 wind-power bases with a million kilowatt capacity each, increasing total wind-power production by 100% to an annual 10 million kilowatts. Solar power capacity is expected to reach 300,000 kilowatt by 2010 – an annual increase of 20%.

Putting a figure on China’s energy needs

1 China’s total primary energy production in 2007 was 2.29 billion standard tons, up 9.4%. Source: Chinese State Statistical Bureau, 24 January 2008

2 BMI, China Power Report Q2 2008

Energy-hungry China plans major investment to boost infrastructure

and develop renewables. Report by Raymond Ng and David Guo.

Need for balance

These statistics highlight China’s massive energy growth needs: the IEA estimates that the country will spend US$3 trillion on electricity infrastructure alone by 2030 in order to meet its growing demand. But where will this investment come from? Will foreign investors be interested if they are not allowed to have a controlling stake? And will these additional investments worsen the environmental issues that China is currently facing? Clearly, the opportunities are enormous. But China will need to strike a careful balance between striving for energy to meet its incredible growth, without endangering the very growth that it is striving to create.

“ China’s planned investment in

transmission and distribution

over the next 25 years will be

almost double that of North

America.” Raymond Ng


Regional reports

Opportunities in Polish energy Report by Jaroslaw Wajer

The good news is that Poland is self-sufficient in electricity, has undergone a program of consolidation

and liberalization, and has successfully unbundled transmission and distribution. Future challenges include

projected capacity shortages, the environmental impact of relying on coal, and the role of the regulator.

All eyes are on Poland’s new center-right government, which was elected in October 2007. Given the sharp price rise (60%) for electricity last year, the energy strategy of the previous government is under scrutiny.

Polish and foreign investors will be watching the progress of Donald Tusk’s new government with interest, to see how it handles the upcoming privatization of the country’s four electricity companies in 2008 and 2009, along with Poland’s need for further (and cleaner) generation and infrastructure upgrades.

Current market structure

Electricity consumption per unit GDP is twice as high in Poland as the rest of the European Union (EU). About 96% of this generation comes from coal1. But with the global price of coal rising rapidly, and active unions in Poland, coal is no longer the reliable, low-cost fuel source it once was.

From March 2006, Poland undertook an ambitious program to consolidate its approximately 30 vertically integrated energy companies (consisting of more than 300 legally independent companies) into 4 vertically integrated organizations. This exercise excluded transmission (see table 3, page 19): these companies are still state-owned, but they are scheduled for privatization during 2008 to 2009.

1 63% hard coal, nearly 23% lignite, according to ARE, the Polish Energy Market Agency


Regional reports

The largest non-Polish players are Sweden’s Vattenfall (generation, distribution, sales), Germany’s RWE (distribution, sales), and France’s EdF (heat and power generation); other companies active in generation only include Belgium’s Electrabel and the Czech Republic’s CEZ.

Transmission is handled by a state-owned company, PSE-Operator. There is third-party access and consumers are free to choose their supplier, but in practice few consumers do so and electricity companies tend to focus their attention on larger businesses.

Entry to the EU and structural reform

Poland’s entry to the EU in 2004 prompted some important structural changes. The first was consolidation, as discussed previously. The second was liberalization. Poland fulfilled its EU requirements to unbundle transmission in June 2004, and distribution in June 2007. Transmission was unbundled in two stages. In 2004, PSE-Operator was set up, which leased transmission assets from its parent company Polish Power Grid Company and was designated by the regulator as a Transmission System Operator. This fulfilled the minimum independence requirements of the EU. In 2007, the second stage of unbundling was finished – PSE-Operator was transformed into a 100% state-owned company on 1 January and granted assets on 31 December. Legal unbundling of distribution took place in June 2007, transforming the 12 state-owned distribution companies into 4.

A third, and much more controversial, effect of EU membership was the removal of a key obstacle to competition: the long-term power purchase agreements (PPAs) between the former transmission grid operator (PSE) and the generation companies. PPAs had long tied up a large proportion of the energy generated in Poland; energy traded on the wholesale market has always been immaterial compared with total production. Effective from 1 April 2008, these agreements ceased – with compensation awarded to the companies for stranded costs.

Role of the regulator

The Polish energy regulator, Urząd Regulacji Energetyki (URE), currently plays an active role in controlling electricity prices charged to customers. This is a contentious issue as many would argue that this role is illegal under EU law; both RWE and Vattenfall are in legal disputes over this issue.

In 2007, when the regulator ended price controls, the (now ex-) government replaced the regulator’s president with one who promptly reinstated price controls. The new government recently announced that electricity prices will be deregulated in January 2009.

As in many countries, there is an ongoing debate between the regulator and the industry over allowable rates of return; unfortunately, the introduction of International Financial Reporting Standards has made the calculation of asset values even more complex.

There are also signs the new regulator will take on a more robust role to support competition. Recently, the regulator criticized consolidation in Poland, saying that decisions had been made against its advice and the State Treasury had not engaged in proper consultation. The regulator is concerned that the four consolidated companies may make use of their dominant positions in the retail market and reduce competition. It believes that only ownership (versus legal) unbundling of distribution will create effective competition, as nowadays liberalization is only ’on paper’.

Source: Ernst & Young analysis based on Polish Energy Market Agency/Polish Energy Regulatory Office data, 2006

Table 3: Poland’s national energy companies

Company Mining Generation market share

Distribution market share

Sales market share

Total installed capacity(MW)

Polish Energy Group (PGE)

2 lignite mines

47% 29% 24% 12,000

Tauron Polska Energia

2 hard coal mines

17% 26% 23% 5,300

ENEA Group n/a 10% 15% 14% 2,880

ENERGA Group n/a 2% (incl. hydro) 17% 15% 1,000


Regional reports

Environmental sustainability

The regulator has focused primarily on affordability of energy: while there is a system of green certificates in place, the issue of sustainability has not been adequately tackled. With such a high percentage of ‘dirty coal’ in its generation mix, Poland is expected to struggle to meet the EU targets of cutting carbon emissions by 25% by 2020.

In terms of renewables, hydro and biomass already account for 5% of generation and there is good potential for onshore wind. The biggest challenges will be insufficient transmission and distribution systems.

Opportunities for non-Polish investors

Currently, the country is a net exporter of energy, selling approximately 8% of total generation to Germany and Norway. But this is projected to change in the next few years, with an expected 5% to 7% capacity shortage2.

New generation plants will need to be built to meet demand (forecast to continue increasing 3% to 5% per year3). And to meet EU environmental targets, future generation will need to include clean coal technologies, renewables and possibly nuclear. To date, no plans to build nuclear plants in Poland have been announced, but the country is investing in a nuclear power plant in Lithuania.

Progress with renewables has been patchy; there is some hydro (2% of current generation) and a system of green certificates is in place. While studies suggest there is good potential for wind power, little has been done to get the industry going and the EU’s target 7.5% generation from renewables by 2020 looks daunting for Poland. The transmission network also needs to be upgraded, along with interconnection to surrounding countries.

Privatization of the four electricity companies also offers good opportunities for foreign investors. From 1998-2004, substantial assets were privatized, so there are good precedents for this round of IPOs. It is worth bearing in mind that labor unions will be entitled to purchase 15% of issued shares of the electricity companies. A key issue will be the legal relationships between parent companies (those being privatized) and subsidiaries, and the rights of subsidiaries to own shares.

“ Poland has already fully unbundled the transmission and distribution of

electricity and natural gas, and a significant privatization program is in

progress. Whilst still looking to enhance choice and competition in its

marketplace, Poland is probably ahead of most Eastern European energy

markets in terms of liberalization: it could be a good indication of how

other markets in the region will develop in the next few years.”

Jaroslaw Wajer

2 Source for all figures: Ernst & Young calculation, based on data from the Polish Energy Market Agency 3 Source: Polish Ministry of Economy


Debating the industry's futureGlobal Power & Utilities Symposium 2008

Industry trends

Ernst & Young will be inviting power and utility industry thought leaders, global executives, and regulation experts to attend. The event will build on the debates initiated in December 2007 at the 2nd Symposium in Düsseldorf, where our interactive roundtables explored three key industry themes:

• Infrastructure: investors in infrastructure want to see a balance between the risks they are taking and the rate of return. Access to capital is not likely to be the problem. However, the attitude and responsibility of the regulator in enabling investment could be a significant hurdle. Regulatory action can be detrimental both in the short term, by limiting revenues that give an adequate return, and in the long term, as any hint of regulatory instability deters investment.

• Generation mix: utilities have tough generation targets to meet and a massive rebuild and expansion of capacity is needed over the next 25 years. Getting the fuel mix right is crucial. Relying on one technology is not viable any more – businesses need to build a portfolio of proven, commercially viable technologies. The markets are capable of financing and delivering these investments, but the legislative and regulatory frameworks need long term vision to be effective.

• Changing markets: markets continue to change, transition processes tend to be long and outcomes uncertain. There is no single ‘perfect’ solution which works well for all stakeholders. Consolidation in the US will provide opportunities for European utilities and for infrastructure funds. Unbundling in Europe will likewise provide significant M&A opportunities. Investors are increasingly likely to specialize in managing the risks inherent in different market sectors – for example, trading wholesale markets, or regulation in transmission. Cross-border and global operations will become more prevalent, putting a real premium on excellent political liaison, regulatory and consumer relations.

We look forward to welcoming you to the 3rd Annual Global Symposium, to continue the debate. For more information on the event, please contact Theresa Hagemeister on + 49 211 9352 10268, or email: [email protected].

In November 2008, Ernst & Young will be hosting its 3rd Annual Global Power & Utilities Symposium.

This year’s event will explore some of the key trends that will fundamentally change the future shape of

the global power and utilities market, in pursuit of readily accessible, affordable and sustainable energy.


Industry trends

Are US utilities ‘powered up’ for IFRS?

US public companies and other interested parties

have been discussing the implications of moving

from US GAAP to IFRS, in a series of roundtables run

by the Securities and Exchange Commission (SEC).

Scott Hartman assesses the challenges ahead.

Adoption of IFRS (International Financial Reporting Standards) in the US would be viewed as a significant change in the accounting world of many US companies. It will require a shift to a more principles-based approach, place far greater reliance on management (and auditor) judgment, and force a degree of process and system change similar to that required for Sarbanes-Oxley compliance. Despite this, the mood so far is positive.

As well as talking with listed companies, the SEC has taken comments from audit firms, investment groups, rating agencies, the legal community and government agencies to help achieve an orderly transition if IFRS is eventually adopted. It is considering whether to allow US filers either the option of adopting IFRS or a date for certain implementation, but thus far no decisions have been made. This means that any implementation is unlikely before 2013.


Industry trends

Challenges for utilities Some significant differences between IFRS and US GAAP (generally accepted accounting principles) are likely to have a particular impact on utility companies. A few of these differences are discussed below.

Accounting by regulated entitiesUnder US GAAP, FAS 71 allows regulated entities to account for certain costs that will be able to be recovered through rates as regulatory assets; conversely, amounts owed back to rate payers can be accounted for as regulated liabilities. There is no comparable provision under IFRS which means that from the regulatory asset perspective, certain costs must be expensed when they are incurred (despite the regulatory provision to recover such costs from ratepayers). This would result in the recording of future revenues with no corresponding cost recognition.

Property, plant and equipmentAccounting for items such as property, plant and equipment may be more granular under IFRS than US GAAP. As US companies are not currently required to account for fixed assets at the component level (although most utilities do account for assets using a retirement unit level), utilities will need to review their current fixed-asset accounting records and determine which components should be depreciated over what estimated useful lives.

Lack of a parallel standard will mean that the treatment of gains and losses arising on disposal of assets belonging to regulated entities will also require review as will the treatment of impairments, and decommissioning obligations for current

operating assets – particularly as the trend towards new nuclear generation and expansion into alternative energy sources gets under way.

Financial instrumentsThis is an area which poses probably the most significant conversion challenge. Commodity contracts and hedging activity play a significant part in the operations of utilities. Although the two relevant accounting standards, FAS 133 (as amended for GAAP purposes) and IAS 39, are somewhat comparable, some fundamental differences will have to be evaluated. The contract detail will be key: contracts will need to be re-evaluated to determine the proper accounting treatment in accordance with IFRS.

Accounting for joint venturesThe treatment of joint ventures, including jointly controlled assets, operations and entities, and the use of pro rata consolidation currently allowed under IFRS, is under review. This is another complex and challenging area which is likely to impact certain operating structures in place in the US utilities industry. While there are varying structures to account for such joint ownership in the US power and utilities industry, we have seen the pro rata consolidation concept used to account for ownership of plants and related assets.

EmissionsDue to a worldwide focus on climate change and mitigating the effects of human activity on the environment, emissions generated by utilities and other companies have received a lot of attention, and this has also raised accounting awareness. Neither US GAAP nor IFRS sheds much light in this area.

However, to date, the bulk of accounting commentary and literature has surfaced in the IFRS arena, so conversion would likely lend additional guidance in this area.

Interaction with federal and state agenciesUS utility companies are regulated by other entities such as the Federal Energy Regulatory Commission (FERC) and state agencies in which they operate, as well as the SEC. IFRS makes no allowance for other regulators and this is not an area likely to be covered by the continuing SEC roundtable discussions and related efforts. Currently, FERC and its accounting rules have become a major part in determining certain accounting policies that have been followed by US utilities. If the concepts of FAS 71 are not adopted or embraced by the IFRS rulemakers, it is quite possible that accounting as required by FERC and other regulatory bodies would be reduced in nature, similar to statutory reporting. As a result, utility groups will need to continue to evaluate accounting for industry-specific issues.

Outlook For now, IFRS is a distant prospect on the US horizon. However, momentum is building and for companies with multiple listings, the adoption of a single global set of accounting standards will be a benefit in terms of process standardization and related efficiency gains. Multiple approaches to financial reporting continue to be inefficient and troublesome, and it appears that there is strong support for the SEC to continue its efforts for transition to IFRS in the US.


Industry trends

Back in 2005, US Congress realized the need for substantial incentives to attract investment capital to transmission and distribution projects. It promptly passed the Energy Policy Act, amended the Federal Power Act (adding section 219) and authorized FERC to offer incentive tariffs for transmission investments. FERC responded by issuing Order 679 and subsequent revisions. The impact of these changes is that on certain new transmission projects, utility companies stand to earn enhanced returns of around 13% after tax. In addition, utility companies will be able to include the cost of construction work in progress in the rate base they charge to customers before the asset has actually been placed in service. How to attract new sources of capital to take advantage of these incentives is a major decision facing US utility businesses today.

Texas may hold key to infrastructure investment

Are REITS right?

Historically, virtually all electric transmission and distribution assets were owned and operated by utilities through traditional corporate entities subject to a corporate-level income tax (i.e., the income is taxed once when earned by the utility, and again when distributed as a dividend to the utility’s shareholders). Utilities now have two alternatives for structuring the ventures that will build and operate these assets, so that the income earned by the owner is subject to a single level of taxation. These are a REIT (real estate investment trust) or an MLP (master limited partnership).

In June 2007, the IRS published a private letter ruling allowing a REIT to own systems such as electric transmission and distribution assets2. This ruling was significant as a REIT generally does not pay tax upon its income, so long as it distributes those earnings to its shareholders as a dividend. A corporation will qualify as a REIT only if it owns certain kinds of asset (real property) and generates certain types of income (including rent from real property).

Some US$1.6 trillion is needed to build North American electric power infrastructure between now and

20301. Tax-efficient investment vehicles could allow companies to attract much-needed additional capital

to these projects, depending on the decision regulators make in a landmark case currently under review

in Texas. Andy Miller assesses the situation.

1 Source: World Energy Outlook 2006, www.worldenergyoutlook.org, © 2006 OECD/IEA; “EPA Enforces Old, New Rules,” Natural Gas Week, 28 March 2005, via Factiva, © 2005 Energy Intelligence Group.

2 PLR 200725015


Industry trends

Under this arrangement, a utility can form a REIT, raise capital through it, build or acquire transmission assets within the REIT, and then lease them to an operator (see diagram below). Hence the REIT owns the transmission or distribution system and earns income from renting the system. This income is distributed by the REIT to its shareholders as a dividend, with the result that the REIT does not pay any income tax. The REIT shareholders pay income tax on the dividends received at ordinary rates. Accordingly, a REIT pays no corporate-level tax, thereby saving a level of income tax and enhancing the after-tax return earned on the investment.

This IRS ruling on a REIT may also apply to MLPs, as the definition of qualifying income for MLPs includes rental income from real property.

Regulatory issues

There are two fundamental issues that need to be resolved for utilities to use this kind of arrangement efficiently. The first is that the cost of the investment needs to be reflected in its rate base. In that regard, the creation of a REIT or MLP appears to remove the asset from the utility.

The second issue is how the regulators will determine the income tax included in the cost of service for ratemaking purposes. Since the REIT pays no corporate-level income tax, will that tax benefit be passed on to the ratepayers in the form of lower tariffs? Alternatively, will the utility and REIT shareholders be able to retain a portion of that tax benefit? In its long-standing Lakehead policy, FERC has already agreed that MLPs operating interstate pipelines may include income tax in the cost of service for ratemaking purposes. Presumably this policy will also apply to REITs since they are similar vehicles3.

The Texas public utility commission (PUC) is currently considering whether, or how, utilities can retain their REIT or MLP investment costs within their rate base, following a request filed by a Texas transmission line owner. We believe there are three options open to the regulators:

• To view the lease as an ‘operating lease’: this would remove the investment from the rate base and effectively eliminate the incentive to use a REIT or an MLP.

• The lease could be considered a ‘capital lease’ for rating

purposes. This re-casts the lease as debt and enables the utility to place the transmission asset on its books, and thereby keep the investment in the rate base – a better solution.

• The utilities might consolidate with the REIT or MLP. This is probably the best option, enabling the utility to keep the assets in the rate base.

Decision may open floodgates

We believe that companies are queuing up to take advantage of this new investment strategy. A favorable decision in Texas would advance the feasibility of this more tax-efficient means to attract capital and fund the investment required by national policy. A decision is anticipated within three to six months.

How it works: financing new transmission projects through a joint venture

1. Utility transfers right to construct transmission assets to Holdco partnership.

2. Utility retains control of Holdco partnership in its capacity as general partner.

3. REIT contributes cash to finance some or all of the transmission assets. Utility contributes remainder of equity to Holdco partnership.

4. Utility retains as much of the equity of Holdco partnership as the parties agree (utility may retain a share of profits in excess of its capital interest).

5. Holdco partnership contributes transmission assets to Opco (disregarded LLC).

6. Utility leases transmission assets from Opco.

7. Holdco partnership and Opco borrow remainder of funds from lender(s).

Lender

Lender

Transmission assets

Holdco partnership

Opco

REITUtility

GP

Lease

LP

3 Although this policy was recently challenged, the court ruled that an MLP may include income tax in its estimated cost of service, even though the partnership does not directly pay tax. See ExxonMobil Oil Corporation v. FERC , D.C. Cir. No. 04-1102, et al. (29 May 2007) and BP West Coast Products, LLC v. FERC, 374 F 3d 1263 (D.C. Cir. 2004)



Industry trends

Coming soon: new ‘performance hub’ for European utilities As market liberalization proceeds and competitive pressures increase,

utilities are set to take a closer look at how a new benchmarking study

could help improve business efficiency and control costs.

Report by Danny Siemes and Gertjan Groen.

European utilities under pressureSince the full liberalization of European energy markets in July 2007, intense pressure has developed for utility businesses to improve internal business performance, to outperform each other, and to compete with new, leaner and hungrier market entrants. Former state energy companies have poured money and resources into redesigning their business operations to cope with the realities of competition (including switching customers and heavy regulatory pressure on tariffs) and to absorb the impact of wholesale price spikes, which are continuing to squeeze retail margins. More recently, they have been focusing on process efficiency and margin improvement.

One major concern is to reduce costs: utilities want to ensure that their ‘cost to serve’ matches the best in the sector. Benchmarking studies can help them to do this by providing comparative data against which they can judge current performance, identify problem areas and drive performance up. However, the benchmarks currently available tend to focus on specific processes or parts of the energy value chain. They tend not to go into detail on

the efficiency of processes, and can therefore lack the degree of insight which companies seek. It can also be hard to tell whether data released by one organization is based on the same definitions as another, so it’s difficult to be sure you are looking at dependable performance comparisons.

New ‘performance hub’ from Ernst & YoungA new initiative from Ernst & Young aims to tackle this issue by providing harmonized, anonymous benchmarking data which goes into considerable detail and is truly comparable across the utilities sector. The new EY Utility Benchmark will be based on information sourced directly from European utilities, based on common key performance indicators (KPIs). It will cover the energy value chain1, concentrating on factors which drive business performance with detailed cost, quality and time measures for each business process. Participants will include both vertically integrated organizations and nonintegrated (including unbundled) utilities, highlighting any correlations between business structure and performance.

“ Utilities need deeper insight into what is driving their performance

forward or holding it back. This new Ernst & Young benchmarking

initiative will compare the efficiency of processes and get to the

heart of cost, quality and timing issues. This will help utilities set

priorities, implement improvements, and measure their progress

in future years.” Danny Siemes

Lessons to learn fromtelecoms industry benchmarking?A comparable benchmarking exercise which Ernst & Young ran in the telecoms sector identified many areas where companies could improve, and many went on to increase the efficiency of their processes on a yearly basis. It would seem there is definitely potential for the utilities sector to achieve a similar level of improvement: a recent national survey2 of ‘cost to serve’ in utility companies revealed performance differences of almost 25%.

Continuous benchmarkingMany organizations benchmark continuously, to be confident they are keeping abreast of best practice. The Ernst & Young benchmark exercise aims to cover the energy value chain from generation, via transmission and retail sales and will address many KPIs such as fuel costs, operational costs, maintenance costs, customer swing, debt write-off, and number of complaints. The first report in the new utilities benchmarking series, based on anonymous data from 15 European utilities, should be available for participants in the third quarter of 2008. The exercise will repeat annually, enabling participants to build the feedback into improved processes and measure the impact on profitability year on year. If your company would like to be involved in the project, please contact Danny Siemes or Gertjan Groen (see page 30 for contact details).

1 Including generation, trade, transmission and retail2 Source: Datamonitor


Industry trends

Surviving the perfect storm Mark D. Steele reports on managing capital program risk and prudency in the utility sector.

Demographic changes, increased demand, regulatory requirements, aging systems and environmental concerns are driving unprecedented capital expenditures across the range of utilities. Expenditures in the US could exceed US$1.5 trillion over the next 20 years (see graph, page 11). The overall success of this planned spend will be measured against traditional project metrics as well as rate recovery of costs.

Key threats to major capital projects

Three factors lengthen the odds against success. Firstly, the universal track record: experience with, and studies of, major projects or mega-projects over the last 30 years consistently demonstrate that a significant percentage of projects fail to meet their budgetary or schedule objectives. Utilities as a subset have not done significantly better. During the last major capital push in the electricity sector, budget overruns and schedule delays were the norm rather than the exception and, as a whole, the industry failed to recover a significant percentage of its capital program costs.

Secondly, market conditions fluctuate and have been trending negatively for the last five years. These conditions include issues of labor availability and cost, financing, commodity availability and prices and major vendor and contractor capacity.

Thirdly, there is the issue of increased regulatory scrutiny. The public checkbook is not infinite. Utility commissions will face increasing pressure to push back on requests for rate increases and will scrutinize project prudency more carefully. Rigorous environmental regulations, as well as greater expectations around financial controls, governance and reporting, will add pressure to utilities facing a major build.

Staying in control

These factors combine in what could be a perfect storm for utility capital programs. Critical to success in this storm is an approach that treats prudency as a strategy rather than as ‘spin’. Such an approach will require effective execution across seven areas:

1. Effective governance including board and executive involvement and oversight, written and enforced policies, clear and appropriate delegation of authority and timely and accurate reporting and communication appropriate to the decision needs at each level.

2. Decision support and documentation including multi-level and standardized databases to support decision-making, careful project documentation, standardized retention policies and built-in geo-specific regulatory sensitivity.

3. Stakeholder alignment including expectations at the executive, public, shareholder, investor and regulatory levels as well as contractual alignment with key team members seeking a shared vision of, and accountability for, success.

4. Organizational structure and capability including type of structure, people, organizational and individual experience and transferable skills.

5. Approach and delivery system including the match between scope definition, organizational capabilities, market and approach, the delivery system and contracting strategy and pricing schemes.

6. Program/project management and controls providing tracking of key assumptions and progress.

7. Risk management including a formal process for planning, risk identification and management.

A project approach which addresses all of these needs stands the best chance of weathering the storm of past practices, volatile market conditions and regulatory scrutiny. Are you ready?

“ Critical to success is an approach that treats prudency

as a strategy rather than as spin.” Mark Steele


Comment

For all kinds of reasons, the days of cheap energy are over – and we had better get used to it. Report by Ben van Gils and Bob Ford.

Who pays?

Ben van GilsGlobal Power & Utilities Leader Ernst & Young Global Power & Utilities Center Düsseldorf, Germany

Europe: forging ahead on environmental issues

The US and European energy markets have many common goals. They want to deliver easily available, sustainable energy at affordable prices, while allowing utility companies to earn a decent profit, and they believe competition is the best way to achieve this. Both markets also face influences that are bound to push up prices for consumers including heavy investment demands and regulatory pressure to reduce emissions. Each market is tackling the issues in a unique way, so how do they compare, what can they learn from each other and most importantly, who will pay the price?

In simple terms, the aims of Europe’s energy policy are to achieve sustainable, secure and competitive energy. All members face the challenges of climate change, increasing dependence on imports and consequent higher energy prices.

Energy accounts for 80% of greenhouse gas emissions in the EU and is at the root of climate change and air pollution. The EU is fully committed to tackling this problem and introduced a cap and trade system for greenhouse gases in 2005. But the system was undermined, because it resulted in a carbon price so low that there was no real disincentive to creating emissions. Stringent proposals are planned for 2013 including – controversially – the auctioning of all emissions permits.

Europe is increasingly dependent on imported hydrocarbons. This carries political and economic risks, particularly the risk of supply failure. At the rate EU power demand is increasing, it is estimated that a US$1 trillion investment in generation alone will be needed over the next 25 years. Predictable markets are essential to encourage this level of long-term investment – but these are not yet in place.

Europe is also increasingly exposed to the effects of price volatility in international energy markets. The EU believes that the international energy market will stimulate fair and competitive energy prices, energy saving and increased investment. However, full liberalization has not yet been achieved and there is an ongoing dispute about whether continued enforced liberalization might in fact lead to higher-priced, less secure energy.

Available, sustainable

AffordableWho pays?

" While the US seems to have a firmer grip on infrastructure funding,

Europe is ahead on environmental issues. Perhaps both markets can

learn from each other." Ben van Gils


Comment

The US power and utilities industry is subject to a complex mix of regulated and unregulated businesses1. Regulation is divided between the Federal Energy Regulatory Commission (FERC) and state public utility commissions (PUCs).

The Energy Policy Act of 2005 was the most significant recent legislative event for the US power and utilities industry. The Act was comprehensive, addressing efficiency, renewables, nuclear power, tax incentives and climate change. It included some incentives for clean coal and renewables, although it stopped short of introducing mandatory targets for renewable power in every state. It also mandated FERC to introduce incentive-based rate treatments of interstate transmission to stimulate capital investment by providing an attractive rate of return. Recent evidence suggests this is beginning to work.

Bob FordAmericas Power & Utilities Sector Leader Ernst & Young Americas Power & Utilities Center Washington DC, US

The federal vision for the US is one of abundant, reliable energy in a fair, competitive market. Again, as in Europe, there is an implicit assumption that competition is the best way to achieve affordable energy prices.

To deliver this US energy vision, FERC has three high-level goals: to promote the development of a strong energy infrastructure; to support competitive markets; and to prevent market manipulation. There are no federal regulations on greenhouse gas emissions – although there are local initiatives such as the Regional Greenhouse Gas Initiative (RGGI) in several states (see ‘The cost of carbon’, page 12) and the California greenhouse gas market. It is becoming increasingly likely that some form of federal capping of carbon-dioxide emissions will be introduced – which should provide a clearer investment environment for existing and future players in the market. But this is also likely to push up prices.

Regulation - impact on prices and investment

The European proposals to auction emissions permits from 2013 will certainly hit energy prices. It has been estimated, for example, that this could cost UK consumers US$12 billion a year2. There is also the controversial possibility that imports from markets with less stringent environmental regulations such as the US may face carbon tariffs.

The ongoing row in Europe over unbundling transmission assets has undoubtedly delayed investment in many countries, although there has been more controlled investment in areas such as the UK, where transmission unbundling has already happened. Ultimately, consumers will just have to accept that increased transmission tariffs are the price they will have to pay for much-needed investment.

Meanwhile, in the US, it seems that well-targeted incentives and regulatory powers can certainly promote the required investment and overrule restrictive local objections. For example, FERC has recently been asked to use its new powers to overrule the Arizona Public Utilities Commission and grant Xcel Energy Services’ request for incentive transmission rates, as part of their plan for a US$1 billion upgrade of their transmission grid. The upgrades will help Xcel’s utilities meet state renewable electricity standards and serve increased power demand in the Upper Midwest.

US: a tangle of regulation, but a tight grip on investment goals

Time for clarity on prices

In both the US and Europe, policy-makers are trying hard to put focused incentives and regulation in place to make sustainable, affordable energy a reality. But the plain fact is that whatever happens, energy prices are bound to rise, as a result of all the factors we have discussed here. So one big question for both territories is: what will the societal cost of clean and renewable fuel be? More expensive production, resulting in big energy price rises, could put jobs at risk.

It will be hard for politicians to present the reality of more expensive energy to the public, but now is the time for clarity and leadership. We cannot allow energy prices to stay low in the short term at the expense of necessary longer-term investment. We have to accept this new reality and deal with the social consequences – or pay a higher price in the future.

1 The industry includes investor-owned utilities, municipal and local government utilities, rural cooperative utilities, state and district government utilities, plus generating and energy service companies

2 Source: The Times, 23 January 2008


Contacts

Ernst & Young contactsIf you would like to discuss any of the issues presented in Utilities unbundled, please feel free to call or email our contributors.

Ernst & Young’s global network of utilities professionals numbers 2,500 worldwide

in 600 locations. The member firms in our global organization work with almost

every utility in the world. Our range of services includes accounting and auditing;

tax reporting, operations and advisory; business risk services; technology and

security risk services; transaction advisory and human capital services.

Patrick CassEnergy Industry Leader, North Central US Direct tel: + 1 502 585 6420 Email: [email protected]

Pat joined Ernst & Young in 2002 as the managing partner of our Louisville office. Currently, he works for the Risk Advisory Services Practice and is the leader of the Energy Industry for the North Central Area. He has 35 years of experience serving power and utility clients in four US markets and coordinating services for clients in more than 20 other countries. In addition to his experience in auditing and risk advisory services, Pat has testified on accounting and ratemaking matters for several electric and gas utilities.

David GuoOil and Gas, Mining and Utilities Analyst, Beijing Direct tel: + 86 10 58153149 Email: [email protected]

David has worked with Ernst & Young as a research analyst in our Beijing office for just over a year focusing on oil & gas, mining, chemicals, utilities, and renewable energy clients. He previously worked with the Investor Group in Toronto, Canada as a financial consultant and investment researcher, and with Motorola Electronics Beijing as a business analyst.

Jennifer FranklinBusiness & Strategic Analysis, Ernst & Young Center for Business Knowledge, US Direct tel: + 1 216 583 1112 Email: [email protected]

Jennifer is a business and strategic analyst focused on the utilities industry. She works with Ernst & Young’s Global and Americas Utilities leadership on a variety of sector, account, and competitor-focused analyses and thought leadership programs.

Joseph FontanaGlobal Utilities & Power Industry Leader, Transaction Advisory Services, USDirect tel: + 1 212 773 3382Email: [email protected]

Joseph has over 20 years’ corporate finance and transaction experience, and 15 years’ experience with power generation and utilities. He has led numerous transactions for strategic buyers and private equity investors in this industry, including electric and gas utilities, independent power producers, electric and gas marketing companies, gas pipelines, LNG plant construction projects, gas storage and T&D outsourcing.

Jens GrabowAnalyst, Global Power & Utilities Center, Germany Direct tel: + 49 211 9352 10170 Email: [email protected]

Jens has been the analyst in Ernst & Young's Global Power & Utilities Center for two years. He assists client teams around the world on major strategic industry issues and is involved in many of Ernst & Young’s thought leadership initiatives. Prior to that, he graduated in energy and environmental management and export engineering.

Gertjan GroenBusiness Advisory Services, TMT Utilities,The NetherlandsDirect tel: + 31 10 406 8606Email: [email protected]

Gertjan has more than 19 years of experience in assurance and advisory services. Before joining Ernst & Young in April 2007, Gertjan worked for two years as operational auditor within the largest Dutch utility company where he gained in-depth knowledge of the utility sector. His focus is on power and gas utility companies. His experience includes performance management, risk management and audit.

Ben van GilsGlobal Power & Utilities Leader Ernst & Young Global Power & Utilities Center Düsseldorf, GermanyDirect tel: + 49 211 9352 21557Email: [email protected]

Ben works with utility and energy companies all over the world. He advises the European and Dutch parliaments on energy matters, writes on energy for the Financial Times and The Wall Street Journal, and has appeared regularly on CNN, the BBC, and Dutch TV.


Contacts

Raymond NgHead of Energy, Chemicals & Utilities, BeijingDirect tel: + 86 10 58153332Email: [email protected]

Raymond has over 20 years of experience in providing auditing, accounting and corporate advisory services for utilities and power businesses in Asia. He also has extensive experience in IPOs on the NASDAQ, NYSE, London Stock Exchange and the Hong Kong Stock Exchange.

Danny SiemesBusiness Advisory Services, The Netherlands Direct tel: + 31 10 406 8492Email: [email protected]

Danny joined Ernst & Young in 2006 and has broad experience in managing complex international projects, predominantly for utilities and telecoms industry clients. He regularly advises on issues including regulatory costing, meter management, interconnection, and convergence, and in 2008 will be leading our new EY Utility Benchmark initiative.

Scott T. HartmanAssurance and Advisory Business Services, USDirect tel: + 1 215 448 3388 Email: [email protected]

Scott has 20 years of experience working with both publicly and privately owned companies, primarily in the US power and utilities and manufacturing industries. He focuses on accounting and auditing, with significant experience in multinational consolidation coordination, financial reporting and Securities and Exchange Commission filings and registrations. Scott is a member of Ernst & Young’s US mid-Atlantic sub-area IFRS desk and also serves on the Global Utilities IFRS Group.

Bob FordAmericas Power & Utilities Sector Leader Ernst & Young Americas Power & Utilities Center Washington DC, US Direct tel: + 1 215 448 5438Email: [email protected]

Bob is an auditor with over 25 years of experience with Ernst & Young, delivering professional services to global clients. Bob has held a series of leadership positions and in his current role as Americas Power & Utilities Sector Leader, he oversees sector knowledge and thought leadership, marketing and assists in people resources.

Jaroslaw WajerBusiness Advisory Services, Utilities, PolandDirect tel: + 48 22 557 7163Email: [email protected]

Jaroslaw has some 10 years’ experience of working with utilities clients at Ernst & Young. He focuses on restructuring projects (including unbundling) and consolidation processes, finance transformation, business processes optimization and regulatory issues, and also has experience in audit, IFRS implementation and due diligence projects.

Mark D. SteeleConstruction & Real Estate Advisory Services, USDirect tel: + 1 215 448 5353Email: [email protected]

Mark has over 19 years of experience in management, engineering, and construction. He is experienced in the evaluation, analysis and risk management of complex capital projects at all stages in their lifecycles and has testified as an expert witness on project schedule delay, labor productivity, and project cost issues. Current assignments include project risk assessment for a Midwestern electrical utilities’ US$1.8 billion capital program.

J. Andrew MillerAmericas Tax Leader, Utilities Sector, USDirect tel: + 1 314 290 1205Email: [email protected]

Andy is responsible for coordinating Ernst & Young’s tax resources for utility and power businesses in the Americas. He has over 25 years’ experience in corporate taxation and due diligence teams for mergers and acquisitions. His clients include several large multinational energy businesses.

Ernst & Young

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About Ernst & YoungErnst & Young is a global leader in assurance, tax, transaction and advisory services. Worldwide, our 130,000 people are united by our shared values and an unwavering commitment to quality. We make a difference by helping our people, our clients and our wider communities achieve potential.

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Ernst & Young refers to the global organization of member firms of Ernst & Young Global Limited, each of which is a separate legal entity. Ernst & Young Global Limited, a UK company limited by guarantee, does not provide services to clients.

About Ernst & Young’s Global Power & Utilities Center In a world of uncertainty, changing regulatory frameworks and environmental challenges, utility companies need to maintain a secure and reliable supply, whilst anticipating change and reacting to it quickly. Ernst & Young’s Global Utilities Center brings together a worldwide team of professionals to help you achieve your potential – a team with deep technical experience in providing assurance, tax, transaction and advisory services. The Center works to anticipate market trends, identify the implications and develop points of view on relevant industry issues. Ultimately it enables us to help you meet your goals and compete more effectively. It’s how Ernst & Young makes a difference.

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© 2008 EYGM Limited. All Rights Reserved.

EYG no. DX0036

This publication contains information in summary form and is therefore intended for general guidance only. It is not intended to be a substitute for detailed research or the exercise of professional judgment. Neither EYGM Limited nor any other member of the global Ernst & Young organization can accept any responsibility for loss occasioned to any person acting or refraining from action as a result of any material in this publication. On any specific matter, reference should be made to the appropriate advisor.

04 Issue Utilities unbundled - EY - US · 2015-07-29 · Utilities unbundled – Issue 04 3...

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